Methods for producing a crude product

ABSTRACT

Methods for conversion of a hydrocarbon feed to a total product are described. Contact of the hydrocarbon feed with one or more catalysts at controlled contacting conditions produces the total product. The total product includes a crude product that is a liquid mixture at 25° C. and 0.101 MPa and has a basic nitrogen content of at most 90% of the basic nitrogen content of the hydrocarbon feed.

RELATED APPLICATION

The present application claims the benefit of the filing date of U.S.Provisional patent application Ser. No. 60/850,109 filed Oct. 6, 2006,the disclosure of which is incorporated herein by reference.

FIELD OF THE INVENTION

The present invention generally relates to systems, methods, andcatalysts for treating hydrocarbon feeds, and to compositions that canbe produced using such systems, methods, and catalysts. Moreparticularly, certain embodiments described herein relate to systems,methods, and catalysts for conversion of a hydrocarbon feed to a totalproduct, wherein the total product includes a crude product that is aliquid mixture at 25° C. and 0.101 MPa and has one or more propertiesthat are changed relative to the respective property of the hydrocarbonfeed.

DESCRIPTION OF RELATED ART

Crudes that have one or more unsuitable properties that do not allow thecrudes to be economically transported, or processed using conventionalfacilities, are commonly referred to as “disadvantaged crudes”.

Disadvantaged crudes may include acidic components that contribute tothe total acid number (“TAN”) of the crude feed. Disadvantaged crudeswith a relatively high TAN may contribute to corrosion of metalcomponents during transporting and/or processing of the disadvantagedcrudes. Removal of acidic components from disadvantaged crudes mayinvolve chemically neutralizing acidic components with various bases.Alternately, corrosion-resistant metals may be used in transportationequipment and/or processing equipment. The use of corrosion-resistantmetal often involves significant expense, and thus, the use ofcorrosion-resistant metal in existing equipment may not be desirable.Another method to inhibit corrosion may involve addition of corrosioninhibitors to disadvantaged crudes before transporting and/or processingof the disadvantaged crudes. The use of corrosion inhibitors maynegatively affect equipment used to process the crudes and/or thequality of products produced from the crudes.

Disadvantaged crudes often contain relatively high levels of residue.Disadvantaged crudes having such high levels of residue tend to bedifficult and expensive to transport and/or process using conventionalfacilities.

Disadvantaged crudes may include relatively high amounts of metalcontaminants, for example, nickel, vanadium, and/or iron. Duringprocessing of such crudes, metal contaminants and/or compounds of metalcontaminants, may deposit on a surface of the catalyst or in the voidvolume of the catalyst. Such deposits may cause a decline in theactivity of the catalyst.

Coke may form and/or deposit on catalyst surfaces at a rapid rate duringprocessing of disadvantaged crudes. It may be costly to regenerate thecatalytic activity of a catalyst contaminated with coke. Hightemperatures used during regeneration may also diminish the activity ofthe catalyst and/or cause the catalyst to deteriorate.

Disadvantaged crudes may include metals in metal salts of organic acids(for example, calcium, potassium and/or sodium). Metals in metal saltsof organic acids are not typically separated from disadvantaged crudesby conventional processes, for example, desalting and/or acid washing.

Processes are often encountered in conventional processes when metals inmetal salts of organic acids are present. In contrast to nickel andvanadium, which typically deposit near the external surface of thecatalyst, metals in metal salts of organic acids may depositpreferentially in void volumes between catalyst particles, particularlyat the top of the catalyst bed. The deposit of contaminants, forexample, metals in metal salts of organic acids, at the top of thecatalyst bed, generally results in an increase in pressure drop throughthe bed and may effectively plug the catalyst bed. Moreover, the metalsin metal salts of organic acids may cause rapid deactivation ofcatalysts.

Disadvantaged crudes often contain organically bound heteroatoms (forexample, sulfur, oxygen, and nitrogen). Organically bound heteroatomsmay, in some situations, have an adverse effect on catalysts.

Disadvantaged crudes may include organic oxygen compounds. Treatmentfacilities that process disadvantaged crudes with an oxygen content ofat least 0.002 grams of oxygen per gram of disadvantaged crude mayencounter problems during processing. Organic oxygen compounds, whenheated during processing, may form higher oxidation compounds (forexample, ketones and/or acids formed by oxidation of alcohols, and/oracids formed by oxidation of ethers) that are difficult to remove fromthe treated crude and/or may corrode/contaminate equipment duringprocessing and cause plugging in transportation lines.

Disadvantaged crudes may include basic nitrogen compounds (for example,pyridine, quinolines, isoquinolines, benzoquinolines, pyrroles,carbazoles, benzocarbazoles, and homologs thereof. Basic nitrogencompounds may have adverse effects on catalysts used in crackingprocesses, thus reducing the efficiency of the cracking operation. Basicnitrogen compounds, when heated during processing, may form highmolecular weight compounds that contribute to gum formation in operatingunits.

Disadvantaged crudes may include hydrogen deficient hydrocarbons. Whenprocessing of hydrogen deficient hydrocarbons, consistent quantities ofhydrogen generally need to be added, particularly if unsaturatedfragments resulting from cracking processes are produced. Hydrogenationduring processing, which typically involves the use of an activehydrogenation catalyst, may be needed to inhibit unsaturated fragmentsfrom forming coke. Hydrogen is costly to produce and/or costly totransport to treatment facilities.

Disadvantaged crudes also tend to exhibit instability during processingin conventional facilities. Crude instability tends to result in phaseseparation of components during processing and/or formation ofundesirable by-products (for example, hydrogen sulfide, water, andcarbon dioxide).

Conventional processes often lack the ability to change a selectedproperty in a disadvantaged crude without also significantly changingother properties in the disadvantaged crude. For example, conventionalprocesses often lack the ability to significantly reduce TAN in adisadvantaged crude while, at the same time, only changing by a desiredamount the content of certain components (such as sulfur or metalcontaminants) in the disadvantaged crude.

Some processes for improving the quality of crude include adding adiluent to disadvantaged crudes to lower the weight percent ofcomponents contributing to the disadvantaged properties. Adding diluent,however, generally increases costs of treating disadvantaged crudes dueto the costs of diluent and/or increased costs to handle thedisadvantaged crudes. Addition of diluent to a disadvantaged crude may,in some situations, decrease stability of such crude.

U.S. Pat. Nos. 6,554,994 to Reynolds et al.; 6,547,957 to Sudhakar etal.; 6,436,280 to Harle et al.; 6,277,269 to Meyers et al.; 6,162,350 toSoled et al.; 6,063,266 to Grande et al.; 5,928,502 to Bearden et al.;5,928,501 to Sudhakar et al.; 5,914,030 to Bearden et al.; 5,897,769 toTrachte et al.; 5,871,636 to Trachte et al.; and 5,851,381 to Tanaka etal.; 5,322,617 to de Bruijn et al.; 4,992,163 to Aldridge et al.;4,937,222 to Angevine et al.; 4,886,594 to Miller; 4,746,419 to Peck etal.; 4,548,710 to Simpson; 4,525,472 to Morales et al.; 4,457,836 toSeiver et al.; 4,499,203 to Toulhoat et al.; 4,389,301 to Dahlberg etal.; 4,191,636 to Fukui et al.; U.S. Published Patent Application Nos.20050133414 through 20050133418 to Bhan et al.; 20050139518 through20050139522 to Bhan et al.; 20050145543 to Bhan et al.; 20050150818 toBhan et al.; 20050155908 to Bhan et al.; 20050167320 to Bhan et al.;20050167324 through 20050167332 to Bhan et al.; 20050173301 through20050173303 to Bhan et al., 20060060510 to Bhan; and U.S. patentapplication Ser. Nos. 11/400,542; 11/400,294; 11/399,843; 11/400,628;and 11/400,295, all entitled “Systems, Methods, and Catalysts forProducing a Crude Product” and all filed Apr. 7, 2006; 11/425,979;11/425,983; 11/425,985 to Bhan all entitled “Systems, Methods, andCatalysts for Producing a Crude Product” and all filed Jun. 6, 2006describe various processes, systems, and catalysts for processingcrudes.

In sum, disadvantaged crudes generally have undesirable properties (forexample, relatively high residue content, a tendency to become unstableduring treatment, and/or a tendency to consume relatively large amountsof hydrogen during treatment). Other undesirable properties includerelatively high amounts of undesirable components (for example, residue,organically bound heteroatoms, metal contaminants, metals in metal saltsof organic acids, and/or organic oxygen compounds). Such properties tendto cause problems in conventional transportation and/or treatmentfacilities, including increased corrosion, decreased catalyst life,process plugging, and/or increased usage of hydrogen during treatment.Thus, there is a significant economic and technical need for improvedsystems, methods, and/or catalysts for conversion of disadvantagedcrudes into crude products with more desirable properties. There is alsoa significant economic and technical need for systems, methods, and/orcatalysts that can change selected properties in a disadvantaged crudewhile only selectively changing other properties in the disadvantagedcrude.

SUMMARY OF THE INVENTION

Inventions described herein generally relate to systems, methods, andcatalyst for conversion of a hydrocarbon feed to a total productcomprising a crude product and, in some embodiments, non-condensablegas. Inventions described herein also generally relate to compositionsthat have novel combinations of components therein. Such compositionscan be obtained by using the systems and methods described herein.

In some embodiments, the invention describes a method of producing acrude product, that includes contacting a hydrocarbon feed with one ormore catalysts to produce a total product that includes the crudeproduct, wherein the crude product is a liquid mixture at 25° C. and0.101 MPa, the hydrocarbon feed having a molybdenum content of at least0.1 wtppm of molybdenum, the hydrocarbon feed having a Ni/V/Fe contentof at least 10 wtppm, at least one of the catalysts comprising one ormore metals from Columns 6-10 of the Periodic Table and/or one or morecompounds of one or more metals from Columns 6-10 of the Periodic Table,and the Columns 6-10 metals catalyst having a pore size distributionwith a median pore diameter of up to 150 angstroms; and controllingcontacting conditions at a temperature of at least 300° C., a partialpressure of hydrogen of at most 7 MPa, and a LHSV of at least 0.1 h⁻¹ toproduce the crude product, the crude product having a molybdenum contentof at most 90% of the molybdenum content of the hydrocarbon feed and aNi/V/Fe content between 80% and 120% of the Ni/V/Fe content of thehydrocarbon feed, wherein molybdenum and Ni/V/Fe contents are asdetermined by ASTM Method D5708 and median pore diameter is asdetermined by ASTM Method D4284.

In some embodiments, the invention describes a method of producing acrude product that includes contacting a hydrocarbon feed with one ormore catalysts to produce a total product that includes the crudeproduct, wherein the crude product is a liquid mixture at 25° C. and0.101 MPa, the hydrocarbon feed having, per gram of hydrocarbon feed, atotal Ni/V/Fe content of at least 0.00002 grams, and a total C₅ and C₇asphaltene content of at least 0.01 grams, and at least one of thecatalysts comprising one or more metals from Columns 6-10 of thePeriodic Table, and/or one or more compounds of one or more metals fromColumns 6-10 of the Periodic Table; and controlling contactingconditions at a temperature of at least 300° C., a partial pressure ofhydrogen of at most 7 MPa, and a LHSV of at least 0.1 h⁻¹ to produce thecrude product, the crude product having a Ni/V/Fe content between 80%and 120% of the Ni/V/Fe content of the hydrocarbon feed and a total C₅and C₇ asphaltene content of at most 90% of the hydrocarbon feed C₅ andC₇ asphaltene content, wherein the C₅ and C₇ asphaltenes content is asum of the C₅ asphaltenes as determined by ASTM Method D2007 and C₇asphaltenes as determined by ASTM Method D3279.

In some embodiments, the invention describes a method of producing acrude product that includes contacting a hydrocarbon feed with one ormore catalysts to produce a total product that includes the crudeproduct, wherein the crude product is a liquid mixture at 25° C. and0.101 MPa, the hydrocarbon feed having, per gram of hydrocarbon feed, atotal Ni/V/Fe content of at least 0.00002 grams, and viscosity of atleast 10 cSt at 37.8° C. and at least one of the catalysts comprisingone or more metals from Column 6 of the Periodic Table, and/or one ormore compounds of one or more metals from Column 6 of the PeriodicTable; and controlling contacting conditions at a temperature of atleast 300° C., a partial pressure of hydrogen of at most 7 MPa, and aLHSV of at least 0.1 h⁻¹ to produce the crude product, the crude producthaving a Ni/V/Fe content between 80% and 120% of the Ni/V/Fe content ofthe hydrocarbon feed and a viscosity at 37.8° C. of at most 50% of theviscosity of the hydrocarbon feed at 37.8° C., wherein viscosity is asdetermined by ASTM Method D445.

In some embodiments, the invention describes a method of producing acrude product that includes contacting a hydrocarbon feed with one ormore catalysts to produce a total product that includes the crudeproduct, wherein the crude product is a liquid mixture at 25° C. and0.101 MPa, the hydrocarbon feed having, per gram of hydrocarbon feed, atotal Ni/V/Fe content of at least 0.00002 grams, and a total residuecontent of at least 0.1 grams, and at least one of the catalystscomprising one or more metals from Columns 6-10 of the Periodic Table,and/or one or more compounds of one or more metals from Columns 6-10 ofthe Periodic Table; and controlling contacting conditions at atemperature of at least 300° C., a partial pressure of hydrogen of atmost 7 MPa, and a LHSV of at least 0.1 h⁻¹ to produce the crude product,the crude product having a Ni/V/Fe content between 80% to 120% of theNi/V/Fe content of the hydrocarbon feed and a residue content of at most90% of the hydrocarbon feed residue content, wherein Ni/V/Fe content isas determined by ASTM Method D5708 and residue content is as determinedby ASTM Method D5307.

In some embodiments, the invention describes a method of producing acrude product that includes contacting a hydrocarbon feed with one ormore catalysts positioned in one or more contacting zones of a fixed bedreactor to produce a total product that includes the crude product,wherein the crude product is a liquid mixture at 25° C. and 0.101 MPa,the hydrocarbon feed having, per gram of hydrocarbon feed, a totalresidue content of at least 0.1 grams, and at least one of the catalystscomprising one or more metals from Column 6 of the Periodic Table,and/or one or more compounds of one or more metals from Column 6 of thePeriodic Table; and controlling contacting conditions at a temperatureof at least 300° C., a partial pressure of hydrogen of at most 7 MPa,and a LHSV of at least 0.1 h⁻¹ to produce the crude product, the crudeproduct a residue content of at most 90% of the hydrocarbon feed residuecontent.

In some embodiments, the invention provides a hydrocarbon compositionthat includes per gram of hydrocarbon composition: at least 0.001 gramsof hydrocarbons with a boiling range distribution between 38° C. and200° C. at 0.101 MPa; at least 0.001 grams of hydrocarbons with aboiling range distribution between 204° C. and 343° C. at 0.101 MPa; atleast 0.001 grams of hydrocarbons with a boiling range distributionbetween 343° C. and 650° C. at 0.101 MPa; at least 0.001 grams ofhydrocarbons with an initial boiling point of at least 650° C. at 0.101MPa; at least 0.000150 grams of Ni/V/Fe; and at most 0.01 grams of C₅asphaltenes.

In some embodiments, the invention describes a method of producing acrude product that includes contacting a hydrocarbon feed with one ormore catalysts to produce a total product that includes the crudeproduct, wherein the crude product is a liquid mixture at 25° C. and0.101 MPa, the hydrocarbon feed having a viscosity of at least 10 cSt at37.8° C.; at least one of the catalysts comprises one or more metalsfrom Columns 6-10 of the Periodic Table and/or one or more compounds ofone or more metals from Columns 6-10 of the Periodic Table; andcontrolling contacting conditions at a temperature from 370° C. to 450°C., a partial pressure of hydrogen of at most 7 MPa, and an liquidhourly space velocity (LHSV) of at least 0.1 h⁻¹ to produce the crudeproduct, the crude product having a viscosity at 37.8° C. of at most 50%of the viscosity of the hydrocarbon feed at 37.8° C., and wherein aP-value of a hydrocarbon feed/total product mixture is at least 1.0during contacting, wherein viscosity is as determined by ASTM MethodD445 and P-Value is as determined by ASTM Method D7060.

In some embodiments, the invention describes a method of treating ahydrocarbon feed that includes contacting a hydrocarbon feed withhydrogen in the presence of one or more catalysts to produce a totalproduct that includes the crude product, wherein the crude product is aliquid mixture at 25° C. and 0.101 MPa and the hydrocarbon feed has aviscosity of at least 10 cSt at 37.8° C.; and controlling contactingconditions at a partial pressure of hydrogen of at most 7 MPa and atemperature of at most 450° C. such that a P-value of a hydrocarbonfeed/total product mixture remains at least 1.0, a total consumption ofhydrogen is at most 80 Nm³/m³, and the crude product has a viscosity ofat most 50% at 37.8° C. of the hydrocarbon feed viscosity, whereinviscosity is as determined by ASTM Method D445 and P-Value is asdetermined by ASTM Method D7060.

In some embodiments, the invention describes a system for treating ahydrocarbon feed that includes an upstream contacting system comprisingone or more catalysts, at least one of the catalysts comprising one ormore metals from Column 6-10 of the Periodic Table, and/or one or morecompounds of one or more metals from Column 6-10 of the Periodic Table;wherein contacting a first feed having a viscosity of at least 100 cStat 37.8° C., with one or more of the catalysts in the upstreamcontacting system at a temperature of at least 300° C., a partialpressure of hydrogen of at most 7 MPa, and a LHSV of at least 0.1 h⁻¹produces a crude product having a viscosity at 37.8° C. of at most 50%of the viscosity of the first feed at 37.8° C.; and a downstreamcontacting system coupled to the upstream contacting system andconfigured to receive and process a feed exiting the upstream contactingsystem, wherein the downstream contacting system is configured tosubject the feed exciting the upstream contacting system to a crackingprocess.

In some embodiments, the invention describes a system for treating ahydrocarbon feed comprising: an upstream contacting system comprisingone or more catalysts, at least one of the catalysts comprising one ormore metals from Column 6 of the Periodic Table, and/or one or morecompounds of one or more metals from Column 6 of the Periodic Table;wherein contacting a first feed having a viscosity of at least 100 cStat 37.8° C., with one or more of the catalysts in the upstreamcontacting system at a temperature of at least 300° C., a partialpressure of hydrogen of at most 7 MPa, and a LHSV of at least 0.1 h⁻¹produces a crude product having a viscosity at 37.8° C. of at most 50%of the viscosity of the first feed at 37.8° C.; and a downstreamcontacting system coupled to the upstream contacting system andconfigured to receive and process a feed exiting the upstream contactingsystem, wherein the downstream contacting system comprises adeasphalting unit.

In some embodiments, the invention describes a system producing a crudeproduct that comprising. an upstream contacting system comprising one ormore catalysts, at least one of the upstream catalysts comprising, pergram of catalyst, 0.0001 grams to 0.1 grams of one or more metals fromColumn 6 of the Periodic Table and/or one or more compounds of one ormore metals from Column 6 of the Periodic Table, wherein contact of ahydrocarbon feed having a molybdenum content of at least 0.1 wtppm ofmolybdenum and at least 0.1 grams of residue per gram of hydrocarbonfeed, with one or more of the catalysts in the upstream contactingsystem at a temperature of at most 450° C. and 7 MPa produces ahydrocarbon feed/total product mixture, the hydrocarbon feed/totalproduct mixture having a molybdenum content of at most 90% of themolybdenum of the hydrocarbon feed; and a downstream contacting zonecoupled to the upstream contacting zone, the downstream contacting zoneconfigured to receive the hydrocarbon feed/total product mixture, thedownstream contacting system comprising one or more catalysts, at leastone of the downstream catalysts comprising, per gram of catalyst, atleast 0.1 grams of one or more metals from Columns 6-10 of the PeriodicTable and/or one or more compounds of one or more metals from Columns6-10 of the Periodic Table, the Columns 6-10 catalyst having a pore sizedistribution with a median pore diameter of between 50 angstrom and 150angstrom, wherein contact of the hydrocarbon feed/total product mixtureat a temperature of at most 450° C. and 7 MPa produces a total productthat includes a crude product, wherein the crude product is a liquidmixture at 25° C. and 0.101 MPa and the crude product has a molybdenumcontent of at most 90% of the molybdenum content of the hydrocarbon feedand at most 90% of the residue content of the hydrocarbon feed. Theinvention also provides a method of producing a crude product withmolybdenum reduction using said system.

In some embodiments, the invention produces a hydrocarbon compositionthat includes at least 0.1 wtppm of molybdenum; at least 0.01 grams ofhydrocarbons having a boiling range distribution between 38° C. and 200°C. per gram of hydrocarbon composition; and at least 0.1 grams ofhydrocarbons having a boiling range distribution between 343° C. and650° C. per gram of hydrocarbon composition.

In some embodiments, the invention provides a method of producing acrude product, that includes contacting a hydrocarbon feed with one ormore catalysts to produce a total product that includes the crudeproduct, wherein the crude product is a liquid mixture at 25° C. and0.101 MPa, the hydrocarbon feed having a basic nitrogen content of atleast 0.0001 grams per gram of hydrocarbon feed, at least one of thecatalysts has at least 0.01 grams of one or more metals from Column 6 ofthe Periodic Table and/or one or more compounds of one or more metalsfrom Column 6 of the Periodic Table per gram of catalyst, the Column 6metal catalyst having a pore size distribution with median pore diameterof between 50 angstroms and 180 angstroms; controlling contactingconditions at a pressure of at least 3 MPa and a temperature of at least300° C. to produce the crude product, the crude product having a basicnitrogen content of at most 90% of the basic nitrogen content of thehydrocarbon feed.

In some embodiments, the invention provides a method of producing acrude product, that includes contacting a hydrocarbon feed with one ormore catalysts to produce a total product that includes the crudeproduct, wherein the crude product is a liquid mixture at 25° C. and0.101 MPa; the hydrocarbon feed has a residue content of at least 0.1grams per gram of hydrocarbon feed; and at least one of the catalysts isobtainable by combining: a supported catalyst; one or more metals fromColumn 6 of the Periodic Table and/or one or more compounds of one ormore metals from Column 6 of the Periodic Table; and a support; andcontrolling contacting conditions at a partial pressure of hydrogen ofleast 3 MPa and a temperature of least 200° C. to produce the crudeproduct; the crude product having a residue content of at most 90% ofthe residue content of the hydrocarbon feed.

In some embodiments, the invention provides a method of producing acrude product that includes contacting a hydrocarbon feed with one ormore catalysts to produce a total product that includes the crudeproduct, wherein the crude product is a liquid mixture at 25° C. and0.101 MPa; the hydrocarbon feed has a micro-carbon residue (MCR) contentof at least 0.0001 grams per gram of hydrocarbon feed; and at least oneof the catalysts has: one or more metals from Column 6 of the PeriodicTable and/or one or more compounds of one or more metals from Column 6of the Periodic Table; and one or more metals from Columns 9-10 of thePeriodic Table and/or one or more compounds of one or more metals fromColumns 9-10 of the Periodic Table; and controlling contactingconditions at a partial pressure of hydrogen of at least 3 MPa and atemperature of at least 200° C. to produce the crude product, the crudeproduct having a MCR content of at most 90% of the MCR content of thehydrocarbon feed, wherein MCR content is as determined by ASTM MethodD4530.

In some embodiments, the invention provides a method of producing acrude product that includes providing one or more catalysts to acontacting zone, wherein at least one of the catalysts is a Column 6metal catalyst, wherein the Column 6 metal catalyst is produced by themethod comprising: combining one or more metals from Column 6 of thePeriodic Table and/or one or more compounds of one or more metals fromColumn 6 of the Periodic Table with a support to form a mixture; andheating the mixture to a temperature of at most 200° C. to form a driedColumn 6 metal catalyst; contacting a hydrocarbon feed with the driedColumn 6 metal catalyst to produce a total product that includes thecrude product, wherein the crude product is a liquid mixture at 25° C.and 0.101 MPa; wherein the hydrocarbon feed has a residue content of atleast 0.1 grams per gram of hydrocarbon feed, and wherein contact of thehydrocarbon feed with the dried catalyst at least partially sulfides thecatalyst; and controlling contacting conditions at a partial pressure ofhydrogen of at least 3 MPa and a temperature of at least 200° C. suchthat the crude product has a residue content of at most 90% of theresidue content of the hydrocarbon feed.

In some embodiments, the invention provides a method of producing acrude product that includes contacting a hydrocarbon feed with one ormore catalysts to produce a total product that includes the crudeproduct, wherein the crude product is a liquid mixture at 25° C. and0.101 MPa; the hydrocarbon feed has a residue content of at least 0.1grams per gram of hydrocarbon feed; and at least one of the catalystshas at most 0.1 grams, per gram of catalyst, of: one or more metals fromColumn 6 of the Periodic Table and/or one or more compounds of one ormore metals from Column 6 of the Periodic Table; and one or more metalsfrom Columns 9-10 of the Periodic Table and/or one or more compounds ofone or more metals from Columns 9-10 of the Periodic Table, and a poresize distribution with a median pore diameter between 50 Å and 120 Å;and controlling contacting conditions at a partial pressure of hydrogenof at least 3 MPa and a temperature of at least 200° C. to produce thecrude product, the crude product having a residue content of at most 90%of the residue content of the hydrocarbon feed.

In some embodiments, the invention provides a method of producing acrude product that includes contacting a crude feed with one or morecatalysts to produce a total product that includes the crude product,wherein the crude product is a liquid mixture at 25° C. and 0.101 MPa;the crude feed having a residue content of at least 0.1 grams per gramof crude feed; and wherein at least one of the catalysts has, per gramof catalyst, at least 0.3 grams of: one or more metals from Columns 6-10of the Periodic Table and/or one or more compounds of one or more metalsfrom Columns 6-10 of the Periodic Table; and a binder; and controllingcontacting conditions at a partial pressure of hydrogen of at least 3MPa and a temperature of at least 200° C. such that the crude producthas a residue content of at most 90% of the residue content of thehydrocarbon feed.

In some embodiments, the invention describes a method of producing acrude product that includes contacting a hydrocarbon feed with one ormore catalysts to produce a total product that includes the crudeproduct, wherein the crude product is a liquid mixture at 25° C. and0.101 MPa; the hydrocarbon feed has a residue content of at least 0.1grams per gram of hydrocarbon feed; and at least one of the catalysts isobtainable by combining: a mineral oxide having an average particlediameter of at most 500 micrometers; one or more metals from Column 6 ofthe Periodic Table and/or one or more compounds of one or more metalsfrom Column 6 of the Periodic Table; and a support; and controllingcontacting conditions at a partial pressure of hydrogen of least 3 MPaand a temperature of least 200° C. to produce the crude product; thecrude product having a residue content of at most 90% of the residuecontent of the hydrocarbon feed.

In some embodiments, the invention provides a method of producing acrude product that includes contacting a hydrocarbon feed with one ormore catalysts to produce a total product that includes the crudeproduct, wherein the crude product is a liquid mixture at 25° C. and0.101 MPa; the hydrocarbon feed has a viscosity of at least 10 cSt at37.8° C.; and at least one of the catalysts is obtainable by combining:a mineral oxide fines; one or more metals from Column 6 of the PeriodicTable and/or one or more compounds of one or more metals from Column 6of the Periodic Table; and a support; and controlling contactingconditions at a partial pressure of hydrogen of at most 7 MPa and atemperature of at most 500° C. to produce the crude product; the crudeproduct having a viscosity content of at most 50% of the hydrocarbonfeed viscosity.

In some embodiments, the invention provides a catalyst that includes asupport, mineral oxides, and one or more metals from Column 6 of thePeriodic Table and/or one or more compounds of one or more metals fromColumn 6 of the Periodic Table, wherein the catalyst has a pore sizedistribution with a median pore diameter of at least 80 Å and thecatalyst is obtainable by combining: a mineral oxide fines; the one ormore of metals from Column 6 of the Periodic Table and/or the one ormore compounds of one or more metals from Column 6 of the PeriodicTable; and a support.

In further embodiments, features from specific embodiments may becombined with features from other embodiments. For example, featuresfrom one embodiment may be combined with features from any of the otherembodiments.

In further embodiments, crude products are obtainable by any of themethods and systems described herein.

In further embodiments, additional features may be added to the specificembodiments described herein.

BRIEF DESCRIPTION OF THE DRAWINGS

Advantages of the present invention will become apparent to thoseskilled in the art with the benefit of the following detaileddescription and upon reference to the accompanying drawings in which:

FIG. 1 is a schematic of an embodiment of a contacting system.

FIGS. 2A and 2B are schematics of embodiments of contacting systems thatinclude two contacting zones.

FIGS. 3A and 3B are schematics of embodiments of contacting systems thatinclude three contacting zones.

FIG. 4 is a schematic of an embodiment of a separation zone incombination with a contacting system.

FIG. 5 is a schematic of an embodiment of a blending zone in combinationwith a contacting system.

FIG. 6 is a schematic of an embodiment of a combination of a separationzone, a contacting system, and a blending zone.

FIG. 7 depicts a Raman spectrum of a vanadium catalyst and variousmolybdenum catalysts.

FIG. 8 is a tabulation of representative properties of crude feed andcrude product for an embodiment of contacting the crude feed with threecatalysts.

FIG. 9 is a graphical representation of weighted average bed temperatureversus length of run for an embodiment of contacting the crude feed withone or more catalysts.

FIG. 10 is a tabulation of representative properties of crude feed andcrude product for an embodiment of contacting the crude feed with twocatalysts.

FIG. 11 is another tabulation of representative properties of crude feedand crude product for an embodiment of contacting the crude feed withtwo catalysts.

FIG. 12 is a tabulation of crude feed and crude products for embodimentsof contacting crude feeds with four different catalyst systems.

FIG. 13 is a graphical representation of P-value of crude productsversus run time for embodiments of contacting crude feeds with fourdifferent catalyst systems.

FIG. 14 is a graphical representation of net hydrogen uptake by crudefeeds versus run time for embodiments of contacting crude feeds withfour different catalyst systems.

FIG. 15 is a graphical representation of residue content, expressed inweight percentage, of crude products versus run time for embodiments ofcontacting crude feeds with four different catalyst systems.

FIG. 16 is a graphical representation of change in API gravity of crudeproducts versus run time for embodiments of contacting the crude feedwith four different catalyst systems.

FIG. 17 is a graphical representation of oxygen content, expressed inweight percentage, of crude products versus run time for embodiments ofcontacting crude feeds with four different catalyst systems.

FIG. 18 is a tabulation of representative properties of crude feed andcrude products for embodiments of contacting the crude feed withcatalyst systems that include various amounts of a molybdenum catalystand a vanadium catalyst, with a catalyst system that include a vanadiumcatalyst and a molybdenum/vanadium catalyst, and with glass beads.

FIG. 19 is a tabulation of properties of crude feed and crude productsfor embodiments of contacting crude feeds with one or more catalysts atvarious liquid hourly space velocities.

FIG. 20 is a tabulation of properties of crude feeds and crude productsfor embodiments of contacting the crude feeds at various contactingtemperatures.

FIG. 21 is a tabulation of crude feed and crude products for embodimentsof contacting the crude feed for greater than 500 hours.

FIG. 22 is a tabulation of crude feed and crude products for embodimentsof contacting the crude feed with a molybdenum catalyst.

FIG. 23 is a tabulation of hydrocarbon feed and crude product forembodiments of contacting the hydrocarbon feed with two catalysts.

FIG. 24 is a tabulation of hydrocarbon feed and crude product forembodiments of contacting the hydrocarbon feed with two catalysts.

FIG. 25 is a tabulation of hydrocarbon feed and crud product for anembodiment of contacting the hydrocarbon feed with a dried catalyst.

While the invention is susceptible to various modifications andalternative forms, specific embodiments thereof are shown by way ofexample in the drawings. The drawings may not be to scale. It should beunderstood that the drawings and detailed description thereto are notintended to limit the invention to the particular form disclosed, but onthe contrary, the intention is to cover all modifications, equivalentsand alternatives falling within the spirit and scope of the presentinvention as defined by the appended claims.

DETAILED DESCRIPTION

Certain embodiments of the inventions are described herein in moredetail. Terms used herein are defined as follows.

“ASTM” refers to American Standard Testing and Materials.

“API gravity” refers to API gravity at 15.5° C. (60° F.). API gravity isas determined by ASTM Method D6822.

Atomic hydrogen percentage and atomic carbon percentage of thehydrocarbon feed and the crude product are as determined by ASTM MethodD5291.

Boiling range distributions for the hydrocarbon feed, the total product,and/or the crude product are as determined by ASTM Method D5307 unlessotherwise mentioned.

“C₅ asphaltenes” refers to asphaltenes that are insoluble in n-pentane.C₅ asphaltenes content is as determined by ASTM Method D2007.

“C₇ asphaltenes” refers to asphaltenes that are insoluble in n-heptane.C₇ asphaltenes content is as determined by ASTM Method D3279.

“Column X metal(s)” refers to one or more metals of Column X of thePeriodic Table and/or one or more compounds of one or more metals ofColumn X of the Periodic Table, in which X corresponds to a columnnumber (for example, 1-12) of the Periodic Table. For example, “Column 6metal(s)” refers to one or more metals from Column 6 of the PeriodicTable and/or one or more compounds of one or more metals from Column 6of the Periodic Table.

“Column X element(s)” refers to one or more elements of Column X of thePeriodic Table, and/or one or more compounds of one or more elements ofColumn X of the Periodic Table, in which X corresponds to a columnnumber (for example, 13-18) of the Periodic Table. For example, “Column15 element(s)” refers to one or more elements from Column 15 of thePeriodic Table and/or one or more compounds of one or more elements fromColumn 15 of the Periodic Table.

In the scope of this application, weight of a metal from the PeriodicTable, weight of a compound of a metal from the Periodic Table, weightof an element from the Periodic Table, or weight of a compound of anelement from the Periodic Table is calculated as the weight of metal orthe weight of element. For example, if 0.1 grams of MoO₃ is used pergram of catalyst, the calculated weight of the molybdenum metal in thecatalyst is 0.067 grams per gram of catalyst.

“Content” refers to the weight of a component in a substrate (forexample, a hydrocarbon feed, a total product, or a crude product)expressed as weight fraction or weight percentage based on the totalweight of the substrate. “Wtppm” refers to parts per million by weight.

“Crude feed” refers to a crude and/or disadvantaged crude that is to betreated herein.

“Crude feed/total product mixture” or “hydrocarbon feed/total product”refers to the mixture that contacts the catalyst during processing.

“Distillate” refers to hydrocarbons with a boiling range distributionbetween 204° C. (400° F.) and 343° C. (650° F.) at 0.101 MPa. Distillatecontent is as determined by ASTM Method D5307.

“Heteroatoms” refers to oxygen, nitrogen, and/or sulfur contained in themolecular structure of a hydrocarbon. Heteroatoms content is asdetermined by ASTM Methods E385 for oxygen, D5762 for total nitrogen,and D4294 for sulfur. “Total basic nitrogen” refers to nitrogencompounds that have a pKa of less than 40. Basic nitrogen (“bn”) is asdetermined by ASTM Method D2896.

“Hydrocarbon feed” refers to a feed that includes hydrocarbons.Hydrocarbon feed may include, but is not limited to, crudes,disadvantaged crudes, hydrocarbons obtained from refinery processes, ormixtures thereof. Examples of hydrocarbon feed obtained from refineryprocesses include, but are not limited to, long residue, short residue,vacuum residue, hydrocarbons boiling above 538° C. (1000° F.), ormixtures thereof.

“Hydrogen source” refers to hydrogen, and/or a compound and/or compoundsthat when in the presence of a hydrocarbon feed and the catalyst reactto provide hydrogen to compound(s) in the hydrocarbon feed. A hydrogensource may include, but is not limited to, hydrocarbons (for example, C₁to C₄ hydrocarbons such as methane, ethane, propane, and butane), water,or mixtures thereof. A mass balance may be conducted to assess the netamount of hydrogen provided to the compound(s) in the hydrocarbon feed.

“Flat plate crush strength” refers to compressive force needed to crusha catalyst. Flat plate crush strength is as determined by ASTM MethodD4179.

“LHSV” refers to a volumetric liquid feed rate per total volume ofcatalyst and is expressed in hours (h⁻¹). Total volume of catalyst iscalculated by summation of all catalyst volumes in the contacting zones,as described herein.

“Liquid mixture” refers to a composition that includes one or morecompounds that are liquid at standard temperature and pressure (25° C.,0.101 MPa, hereinafter referred to as “STP”), or a composition thatincludes a combination of one of more compounds that are liquid at STPwith one or more compounds that are solids at STP.

“Periodic Table” refers to the Periodic Table as specified by theInternational Union of Pure and Applied Chemistry (IUPAC), November2003.

“Metals in metal salts of organic acids” refer to alkali metals,alkaline-earth metals, zinc, arsenic, chromium, or combinations thereof.A content of metals in metal salts of organic acids is as determined byASTM Method D1318.

“Micro-Carbon Residue” (“MCR”) content refers to a quantity of carbonresidue remaining after evaporation and pyrolysis of a substrate. MCRcontent is as determined by ASTM Method D4530.

“Molybdenum content in the hydrocarbon feed” refers to the content ofmolybdenum in the feed. The molybdenum content includes the amount ofinorganic molybdenum and organomolybdenum in the feed. Molybdenumcontent in the hydrocarbon feed is as determined by ASTM Method D5807.

“Naphtha” refers to hydrocarbon components with a boiling rangedistribution between 38° C. (100° F.) and 200° C. (392° F.) at 0.101MPa. Naphtha content is as determined by ASTM Method D5307.

“Ni/V/Fe” refers to nickel, vanadium, iron, or combinations thereof.

“Ni/V/Fe content” refers to the content of nickel, vanadium, iron, orcombinations thereof. The Ni/V/Fe content includes inorganic nickel,vanadium and iron compounds and/or organonickel, organovanadium, andorganoiron compounds. The Ni/V/Fe content is as determined by ASTMMethod D5708.

“Nm³/m³” refers to normal cubic meters of gas per cubic meter ofhydrocarbon feed.

“Non-carboxylic containing organic oxygen compounds” refers to organicoxygen compounds that do not have a carboxylic (—CO₂—) group.Non-carboxylic containing organic oxygen compounds include, but are notlimited to, ethers, cyclic ethers, alcohols, aromatic alcohols, ketones,aldehydes, or combinations thereof, which do not have a carboxylicgroup.

“Non-condensable gas” refers to components and/or mixtures of componentsthat are gases at STP.

“P (peptization) value” or “P-value” refers to a numeral value, whichrepresents the flocculation tendency of asphaltenes in the hydrocarbonfeed. P-Value is as determined by ASTM Method D7060.

“Pore diameter”, “median pore diameter”, and “pore volume” refer to porediameter, median pore diameter, and pore volume, as determined by ASTMMethod D4284 (mercury porosimetry at a contact angle equal to 140°). AMicromeritics® A9220 instrument (Micromeritics Inc., Norcross, Ga.,U.S.A.) may be used to determine these values.

“Organometallic” refers to compound that includes an organic compoundbonded or complexed with a metal of the Periodic Table. “Organometalliccontent” refers to the total content of metal in the organometalliccompounds. Organometallic content is as determined by ASTM Method D5807.

“Residue” refers to components that have a boiling range distributionabove 538° C. (1000° F.), as determined by ASTM Method D5307.

“Sediment” refers to impurities and/or coke that are insoluble in thehydrocarbon feed/total product mixture. Sediment is as determined byASTM Method D4807. Sediment may also be determined by the Shell HotFiltration Test (“SHFST”) as described by Van Kenoort et al. in theJour. Inst. Pet., 1951, pages 596-604.

“SCFB” refers to standard cubic feet of gas per barrel of hydrocarbonfeed.

“Surface area” of a catalyst is as determined by ASTM Method D3663.

“TAN” refers to a total acid number expressed as milligrams (“mg”) ofKOH per gram (“g”) of sample. TAN is as determined by ASTM Method D664.

“Used catalyst” refers to one or more catalysts that have been contactedwith a hydrocarbon feed. A used catalyst includes, but is not limitedto, a catalyst that has been contacted with a hydrocarbon feed and whichhas undergone further treatment (for example, regenerated catalysts).

“VGO” refers to hydrocarbons with a boiling range distribution between343° C. (650° F.) and 538° C. (1000° F.) at 0.101 MPa. VGO content is asdetermined by ASTM Method D5307.

“Viscosity” refers to kinematic viscosity at 37.8° C. (100° F.).Viscosity is as determined using ASTM Method D445.

In the context of this application, it is to be understood that if thevalue obtained for a property of the substrate tested is outside oflimits of the test method, the test method may be modified and/orrecalibrated to test for such property.

Crudes may be produced and/or retorted from hydrocarbon containingformations and then stabilized. Crudes are generally solid, semi-solid,and/or liquid. Crudes may include crude oil. Stabilization may include,but is not limited to, removal of non-condensable gases, water, salts,or combinations thereof from the crude to form a stabilized crude. Suchstabilization may often occur at, or proximate to, the production and/orretorting site.

Stabilized crudes typically have not been distilled and/or fractionallydistilled in a treatment facility to produce multiple components withspecific boiling range distributions (for example, naphtha, distillates,VGO, and/or lubricating oils). Distillation includes, but is not limitedto, atmospheric distillation methods and/or vacuum distillation methods.Undistilled and/or unfractionated stabilized crudes may includecomponents that have a carbon number above 4 in quantities of at least0.5 grams of components per gram of crude. Examples of stabilized crudesinclude whole crudes, topped crudes, desalted crudes, desalted toppedcrudes, or combinations thereof. “Topped” refers to a crude that hasbeen treated such that at least some of the components that have aboiling point below 35° C. at 0.101 MPa (95° F. at 1 atm) have beenremoved. Typically, topped crudes will have a content of at most 0.1grams, at most 0.05 grams, or at most 0.02 grams of such components pergram of the topped crude.

Some stabilized crudes have properties that allow the stabilized crudesto be transported to conventional treatment facilities by transportationcarriers (for example, pipelines, trucks, or ships). Other crudes haveone or more unsuitable properties that render them disadvantaged.Disadvantaged crudes may be unacceptable to a transportation carrierand/or a treatment facility, thus imparting a low economic value to thedisadvantaged crude. The economic value may be such that a reservoirthat includes the disadvantaged crude that is deemed too costly toproduce, transport, and/or treat.

Properties of disadvantaged crudes may include, but are not limited to:a) TAN of at least 0.1, at least 0.3, or at least 1; b) viscosity of atleast 10 cSt; c) API gravity at most 19, at most 15, or at most 10; d) atotal Ni/V/Fe content of at least 0.00002 grams or at least 0.0001 gramsof Ni/V/Fe per gram of crude; e) a total heteroatoms content of at least0.005 grams of heteroatoms per gram of crude; f) a residue content of atleast 0.01 grams of residue per gram of crude; g) a C₅ asphaltenescontent of at least 0.04 grams of C₅ asphaltenes per gram of crude; h) aMCR content of at least 0.002 grams of MCR per gram of crude; i) acontent of metals in metal salts of organic acids of at least 0.00001grams of metals per gram of crude; or j) combinations thereof. In someembodiments, disadvantaged crude may include, per gram of disadvantagedcrude, at least 0.2 grams of residue, at least 0.3 grams of residue, atleast 0.5 grams of residue, or at least 0.9 grams of residue. In someembodiments, the disadvantaged crude may have a TAN in a range from 0.1or 0.3 to 20, 0.3 or 0.5 to 10, or 0.4 or 0.5 to 5. In certainembodiments, disadvantaged crudes, per gram of disadvantaged crude, mayhave a sulfur content of at least 0.005, at least 0.01, or at least 0.02grams.

In some embodiments, disadvantaged crudes have properties including, butnot limited to: a) TAN of at least 0.5 or at least 1; b) an oxygencontent of at least 0.005 grams of oxygen per gram of disadvantagedcrude; c) a C₅ asphaltenes content of at least 0.04 grams of C₅asphaltenes per gram of disadvantaged crude; d) a higher than desiredviscosity (for example, >10 cSt for a hydrocarbon feed with API gravityof at least 5; e) a content of metals in metal salts of organic acids ofat least 0.00001 grams of metals per gram of crude; or f) combinationsthereof.

In some embodiments, disadvantaged crudes have properties including, butnot limited to: a) a basic nitrogen content of at least 0.0001 grams ofbasic nitrogen compounds per gram of disadvantaged crude; b) amolybdenum content of at least 0.1 wtppm; c) a residue content of atleast 0.3 grams of residue per gram of disadvantaged crude; or d)combinations thereof.

Disadvantaged crudes may include, per gram of disadvantaged crude: atleast 0.001 grams, at least 0.005 grams, or at least 0.01 grams ofhydrocarbons with a boiling range distribution between 95° C. and 200°C. at 0.101 MPa; at least 0.01 grams, at least 0.005 grams, or at least0.001 grams of hydrocarbons with a boiling range distribution between200° C. and 300° C. at 0.101 MPa; at least 0.001 grams, at least 0.005grams, or at least 0.01 grams of hydrocarbons with a boiling rangedistribution between 300° C. and 400° C. at 0.101 MPa; and at least0.001 grams, at least 0.005 grams, or at least 0.01 grams ofhydrocarbons with a boiling range distribution between 400° C. and 650°C. at 0.101 MPa.

Disadvantaged crudes may include, per gram of disadvantaged crude: atleast 0.001 grams, at least 0.005 grams, or at least 0.01 grams ofhydrocarbons with a boiling range distribution of at most 100° C. at0.101 MPa; at least 0.001 grams, at least 0.005 grams, or at least 0.01grams of hydrocarbons with a boiling range distribution between 100° C.and 200° C. at 0.101 MPa; at least 0.001 grams, at least 0.005 grams, orat least 0.01 grams of hydrocarbons with a boiling range distributionbetween 200° C. and 300° C. at 0.101 MPa; at least 0.001 grams, at least0.005 grams, or at least 0.01 grams of hydrocarbons with a boiling rangedistribution between 300° C. and 400° C. at 0.101 MPa; and at least0.001 grams, at least 0.005 grams, or at least 0.01 grams ofhydrocarbons with a boiling range distribution between 400° C. and 650°C. at 0.101 MPa.

Some disadvantaged crudes may include, per gram of disadvantaged crude,at least 0.001 grams, at least 0.005 grams, or at least 0.01 grams ofhydrocarbons with a boiling range distribution of at most 100° C. at0.101 MPa, in addition to higher boiling components. Typically, thedisadvantaged crude has, per gram of disadvantaged crude, a content ofsuch hydrocarbons of at most 0.2 grams or at most 0.1 grams.

Some disadvantaged crudes may include, per gram of disadvantaged crude,at least 0.001 grams, at least 0.005 grams, or at least 0.01 grams ofhydrocarbons with a boiling range distribution of at least 200° C. at0.101 MPa.

Some disadvantaged crudes may include, per gram of disadvantaged crude,at least 0.001 grams, at least 0.005 grams, or at least 0.01 grams ofhydrocarbons with a boiling range distribution of at least 650° C.

Examples of disadvantaged crudes that might be treated using theprocesses described herein include, but are not limited to, crudes fromof the following regions of the world: U.S. Gulf Coast and southernCalifornia, Canada Tar sands, Brazilian Santos and Campos basins,Egyptian Gulf of Suez, Chad, United Kingdom North Sea, Angola Offshore,Chinese Bohai Bay, Venezuelan Zulia, Malaysia, and Indonesia Sumatra.

Treatment of disadvantaged crudes may enhance the properties of thedisadvantaged crudes such that the crudes are acceptable fortransportation and/or treatment.

The crude feed may be topped, as described herein. The crude productresulting from treatment of the crude feed, as described herein, isgenerally suitable for transporting and/or treatment. Properties of thecrude product produced as described herein are closer to thecorresponding properties of West Texas Intermediate crude than the crudefeed, or closer to the corresponding properties of Brent crude, than thecrude feed, thereby enhancing the economic value of the crude feed. Suchcrude product may be refined with less or no pre-treatment, therebyenhancing refining efficiencies. Pre-treatment may includedesulfurization, demetallization, and/or atmospheric distillation toremove impurities.

Treatment of a hydrocarbon feed in accordance with inventions describedherein may include contacting the hydrocarbon feed with the catalyst(s)in a contacting zone and/or combinations of two or more contactingzones. In a contacting zone, at least one property of a hydrocarbon feedmay be changed by contact of the hydrocarbon feed with one or morecatalysts relative to the same property of the hydrocarbon feed. In someembodiments, contacting is performed in the presence of a hydrogensource. In some embodiments, the hydrogen source is one or morehydrocarbons that under certain contacting conditions react to providerelatively small amounts of hydrogen to compound(s) in the hydrocarbonfeed.

FIG. 1 is a schematic of contacting system 100 that includes an upstreamcontacting zone 102. The hydrocarbon feed enters upstream contactingzone 102 via hydrocarbon feed conduit 104. A contacting zone may be areactor, a portion of a reactor, multiple portions of a reactor, orcombinations thereof. Examples of a contacting zone include a stackedbed reactor, a fixed bed reactor, an ebullating bed reactor, acontinuously stirred tank reactor (“CSTR”), a fluidized bed reactor, aspray reactor, and a liquid/liquid contactor. In certain embodiments,the contacting system is on or coupled to an offshore facility. Contactof the hydrocarbon feed with the catalyst(s) in contacting system 100may be a continuous process or a batch process.

The contacting zone may include one or more catalysts (for example, twocatalysts). In some embodiments, contact of the hydrocarbon feed with afirst catalyst of the two catalysts may reduce TAN of the hydrocarbonfeed. Subsequent contact of the reduced TAN hydrocarbon feed with thesecond catalyst decreases heteroatoms content and increases API gravity.In other embodiments, TAN, viscosity, Ni/V/Fe content, heteroatomscontent, residue content, API gravity, or combinations of theseproperties of the crude product change by at least 10% relative to thesame properties of the hydrocarbon feed after contact of the hydrocarbonfeed with one or more catalysts.

In certain embodiments, a volume of catalyst in the contacting zone isin a range from 10-60 vol %, 20-50 vol %, or 30-40 vol % of a totalvolume of hydrocarbon feed in the contacting zone. In some embodiments,a slurry of catalyst and hydrocarbon feed may include from 0.001-10grams, 0.005-5 grams, or 0.01-3 grams of catalyst per 100 grams ofhydrocarbon feed in the contacting zone.

Contacting conditions in the contacting zone may include, but are notlimited to, temperature, pressure, hydrogen source flow, hydrocarbonfeed flow, or combinations thereof. Contacting conditions in someembodiments are controlled to produce a crude product with specificproperties. Temperature in the contacting zone may range from 50° C. to500° C., 60° C. to 440° C., 70° C. to 430° C., 80° C. to 420° C. In someembodiments, temperature in a contacting zone may range from 350° C. to450° C., 360° C. to 44° C., 370° C. to 430° C., or from 380° C. to 410°C. LHSV of the hydrocarbon feed will generally range from 0.1 to 30 h⁻¹,0.4 h⁻¹ to 25 h⁻¹ 0.5 to 20 h⁻¹, 1 to 15 h⁻¹, 1.5 to 10 h⁻¹, or 2 to 5h⁻¹. In some embodiments, LHSV is at least 5 h⁻¹, at least 11 h⁻¹, atleast 15 h⁻, or at least 20 h⁻¹. A partial pressure of hydrogen in thecontacting zone may range from 0.1-8 MPa, 1-7 MPa, 2-6 MPa, or 3-5 MPa.In some embodiments, a partial pressure of hydrogen may be at most 7MPa, at most 6 MPa, at most 5 MPa, at most 4 MPa, at most 3 MPa, or atmost 3.5 MPa, or at most 2 MPa.

In embodiments in which the hydrogen source is supplied as a gas (forexample, hydrogen gas), a ratio of the gaseous hydrogen source to thehydrocarbon feed typically ranges from 0.1-100,000 Nm³/m³, 0.5-10,000Nm³/m³, 1-8,000 Nm³/m³, 2-5,000 Nm³/m³, 5-3,000 Nm³/m³, or 10-800 Nm³/m³contacted with the catalyst(s). The hydrogen source, in someembodiments, is combined with carrier gas(es) and recirculated throughthe contacting zone. Carrier gas may be, for example, nitrogen, helium,and/or argon. The carrier gas may facilitate flow of the hydrocarbonfeed and/or flow of the hydrogen source in the contacting zones(s). Thecarrier gas may also enhance mixing in the contacting zone(s). In someembodiments, a hydrogen source (for example, hydrogen, methane orethane) may be used as a carrier gas and recirculated through thecontacting zone.

The hydrogen source may enter upstream contacting zone 102 co-currentlywith the hydrocarbon feed in hydrocarbon feed conduit 104 or separatelyvia gas conduit 106. In upstream contacting zone 102, contact of thehydrocarbon feed with a catalyst produces a total product that includesa crude product, and, in some embodiments, gas. In some embodiments, acarrier gas is combined with the hydrocarbon feed and/or the hydrogensource in conduit 106. The total product may exit upstream contactingzone 102 and enter downstream separation zone 108 via total productconduit 110.

In downstream separation zone 108, the crude product and gas may beseparated from the total product using generally known separationtechniques, for example, gas-liquid separation. The crude product mayexit downstream separation zone 108 via crude product conduit 112, andthen be transported to transportation carriers, pipelines, storagevessels, refineries, other processing zones, or a combination thereof.The gas may include gas formed during processing (for example, hydrogensulfide, carbon dioxide, and/or carbon monoxide), excess gaseoushydrogen source, and/or carrier gas. The excess gas may be recycled tocontacting system 100, purified, transported to other processing zones,storage vessels, or combinations thereof.

In some embodiments, contacting the hydrocarbon feed with thecatalyst(s) to produce a total product is performed in two or morecontacting zones. The total product may be separated to form the crudeproduct and gas(es).

FIGS. 2-3 are schematics of embodiments of contacting system 100 thatincludes two or three contacting zones. In FIGS. 2A and 2B, contactingsystem 100 includes upstream contacting zone 102 and downstreamcontacting zone 114. FIGS. 3A and 3B include contacting zones 102, 114,116. In FIGS. 2A and 3A, contacting zones 102, 114, 116 are depicted asseparate contacting zones in one reactor. The hydrocarbon feed entersupstream contacting zone 102 via hydrocarbon feed conduit 104.

In some embodiments, the carrier gas is combined with the hydrogensource in gas conduit 106 and is introduced into the contacting zones asa mixture. In certain embodiments, as shown in FIGS. 3A and 3B, thehydrogen source and/or the carrier gas may enter the one or morecontacting zones with the hydrocarbon feed separately via gas conduit106 and/or in a direction counter to the flow of the hydrocarbon feedvia, for example, gas conduit 106′. Addition of the hydrogen sourceand/or the carrier gas counter to the flow of the hydrocarbon feed mayenhance mixing and/or contact of the hydrocarbon feed with the catalyst.

Contact of the hydrocarbon feed with catalyst(s) in upstream contactingzone 102 forms a feed stream. The feed stream flows from upstreamcontacting zone 102 to downstream contacting zone 114. In FIGS. 3A and3B, the feed stream flows from downstream contacting zone 114 toadditional downstream contacting zone 116.

Contacting zones 102, 114, 116 may include one or more catalysts. Asshown in FIG. 2B, the feed stream exits upstream contacting zone 102 viafeed stream conduit 118 and enters downstream contacting zone 114. Asshown in FIG. 3B, the feed stream exits downstream contacting zone 114via conduit 118 and enters additional downstream contacting zone 116.

The feed stream may be contacted with additional catalyst(s) indownstream contacting zone 114 and/or additional downstream contactingzone 116 to form the total product. The total product exits downstreamcontacting zone 114 and/or additional downstream contacting zone 116 andenters downstream separation zone 108 via total product conduit 110. Thecrude product and/or gas is (are) separated from the total product. Thecrude product exits downstream separation zone 108 via crude productconduit 112.

FIG. 4 is a schematic of an embodiment of a separation zone upstream ofcontacting system 100. The disadvantaged crude (either topped oruntopped) enters upstream separation zone 120 via crude conduit 122. Inupstream separation zone 120, at least a portion of the disadvantagedcrude is separated using techniques known in the art (for example,sparging, membrane separation, pressure reduction) to produce thehydrocarbon feed. For example, water may be at least partially separatedfrom the disadvantaged crude. In another example, components that have aboiling range distribution below 95° C. or below 100° C. may be at leastpartially separated from the disadvantaged crude to produce thehydrocarbon feed. In some embodiments, at least a portion of naphtha andcompounds more volatile than naphtha are separated from thedisadvantaged crude. In some embodiments, at least a portion of theseparated components exit upstream separation zone 120 via conduit 124.

The hydrocarbon feed obtained from upstream separation zone 120, in someembodiments, includes a mixture of components with a boiling rangedistribution of at least 100° C. or, in some embodiments, a boilingrange distribution of at least 120° C. Typically, the separatedhydrocarbon feed includes a mixture of components with a boiling rangedistribution between 100-1000° C., 120-900° C., or 200-800° C. At leasta portion of the hydrocarbon feed exits upstream separation zone 120 andenters contacting system 100 (see, for example, the contacting zones inFIGS. 1-3) via additional hydrocarbon feed conduit 126 to be furtherprocessed to form a crude product. In some embodiments, upstreamseparation zone 120 may be positioned upstream or downstream of adesalting unit. After processing, the crude product exits contactingsystem 100 via crude product conduit 112.

In some embodiments, the crude product is blended with a crude that isthe same as or different from the hydrocarbon feed. For example, thecrude product may be combined with a crude having a different viscositythereby resulting in a blended product having a viscosity that isbetween the viscosity of the crude product and the viscosity of thecrude. In another example, the crude product may be blended with crudehaving a TAN that is different, thereby producing a product that has aTAN that is between the TAN of the crude product and the crude. Theblended product may be suitable for transportation and/or treatment.

As shown in FIG. 5, in certain embodiments, hydrocarbon feed enterscontacting system 100 via hydrocarbon feed conduit 104, and at least aportion of the crude product exits contacting system 100 via conduit 128and is introduced into blending zone 130. In blending zone 130, at leasta portion of the crude product is combined with one or more processstreams (for example, a hydrocarbon stream such as naphtha produced fromseparation of one or more hydrocarbon feeds), a crude, a hydrocarbonfeed, or mixtures thereof, to produce a blended product. The processstreams, hydrocarbon feed, crude, or mixtures thereof are introduceddirectly into blending zone 130 or upstream of such blending zone viastream conduit 132. A mixing system may be located in or near blendingzone 130. The blended product may meet product specifications designatedby refineries and/or transportation carriers. Product specificationsinclude, but are not limited to, a range of or a limit of API gravity,TAN, viscosity, or combinations thereof. The blended product exitsblending zone 130 via blend conduit 134 to be transported or processed.

In FIG. 6, the disadvantaged crude enters upstream separation zone 120through crude conduit 122, and the disadvantaged crude is separated aspreviously described to form the hydrocarbon feed. The hydrocarbon feedthen enters contacting system 100 through additional hydrocarbon feedconduit 126. At least some components from the disadvantaged crude exitseparation zone 120 via conduit 124. At least a portion of the crudeproduct exits contacting system 100 and enters blending zone 130 throughcrude product conduit 128. Other process streams and/or crudes enterblending zone 130 directly or via stream conduit 132 and are combinedwith the crude product to form a blended product. The blended productexits blending zone 130 via blend conduit 134.

In some embodiments, the crude product and/or the blended product aretransported to a refinery and distilled and/or fractionally distilled toproduce one or more distillate fractions. The distillate fractions maybe processed to produce commercial products such as transportation fuel,lubricants, or chemicals.

In some embodiments, after contact of the hydrocarbon feed with thecatalyst, the crude product has a TAN of at most 90%, at most 50%, or atmost 10% of the TAN of the hydrocarbon feed. In certain embodiments, thecrude product has a TAN of at most 1, at most 0.5, at most 0.3, at most0.2, at most 0.1, or at most 0.05. TAN of the crude product willfrequently be at least 0.0001 and, more frequently, at least 0.001. Insome embodiments, TAN of the crude product may be in a range from 0.001to 0.5, 0.01 to 0.2, or 0.05 to 0.1. In some embodiments, TAN of thecrude product may range from 0.001 to 0.5, 0.004 to 0.4, from 0.01 to0.3, or from 0.1 to 0.2.

In some embodiments, the crude product has a total Ni/V/Fe content of atmost 90%, at most 50%, at most 10%, at most 5%, or at most 3% of theNi/V/Fe content of the hydrocarbon feed. In certain embodiments, thecrude product has, per gram of crude product a total Ni/V/Fe content ina range from 1×10⁻⁷ grams to 5×10⁻⁵ grams, 3×10⁻⁷ grams to 2×10⁻⁵ grams,or 1×10⁻⁶ grams to 1×10⁻⁵ grams. In certain embodiments, the crudeproduct has at most 2×10⁻⁵ grams of Ni/V/Fe. In some embodiments, atotal Ni/V/Fe content of the crude product is 70-130%, 80-120%, or90-110% of the Ni/V/Fe content of the hydrocarbon feed.

In some embodiments, the crude product has a total molybdenum content ofat most 90%, at most 50%, at most 10%, at most 5%, or at most 3% of themolybdenum content of the hydrocarbon feed. In certain embodiments, thecrude product has a total molybdenum content ranging from 0.001 wtppm to1 wtppm, from 0.005 wtppm to 0.05 wtppm, or from 0.01 to 0.1 wtppm.

In some embodiments, the crude product has a total content of metals inmetal salts of organic acids of at most 90%, at most 50%, at most 10%,or at most 5% of the total content of metals in metal salts of organicacids in the hydrocarbon feed. Organic acids that generally form metalsalts include, but are not limited to, carboxylic acids, thiols, imides,sulfonic acids, and sulfonates. Examples of carboxylic acids include,but are not limited to, naphthenic acids, phenanthrenic acids, andbenzoic acid. The metal portion of the metal salts may include alkalimetals (for example, lithium, sodium, and potassium), alkaline-earthmetals (for example, magnesium, calcium, and barium), Column 12 metals(for example, zinc and cadmium), Column 15 metals (for example arsenic),Column 6 metals (for example, chromium), or mixtures thereof.

In certain embodiments, the crude product has a total content of metalsin metal salts of organic acids, per gram of crude product, in a rangefrom 0.0000001 grams to 0.00005 grams, 0.0000003 grams to 0.00002 grams,or 0.000001 grams to 0.00001 grams of metals in metal salt of organicacids per gram of crude product. In some embodiments, a total content ofmetals in metal salts of organic acids of the crude product is 70-130%,80-120%, or 90-110% of the total content of metals in metal salts oforganic acids in the hydrocarbon feed.

In certain embodiments, API gravity of the crude product produced fromcontact of the hydrocarbon feed with catalyst, at the contactingconditions, is 70-130%, 80-120%, 90-110%, or 100-130% of the API gravityof the hydrocarbon feed. In certain embodiments, API gravity of thecrude product is from 14-40, 15-30, or 16-25.

In certain embodiments, the crude product has a viscosity of at most90%, at most 80%, or at most 70% of the viscosity of the hydrocarbonfeed. In some embodiments, the viscosity of the crude product is at most90% of the viscosity of the hydrocarbon feed while the API gravity ofthe crude product is 70-130%, 80-120%, or 90-110% of the API gravity thehydrocarbon feed.

In some embodiments, the crude product has a total heteroatoms contentof at most 90%, at most 50%, at most 10%, or at most 5% of the totalheteroatoms content of the hydrocarbon feed. In certain embodiments, thecrude product has a total heteroatoms content of at least 1%, at least30%, at least 80%, or at least 99% of the total heteroatoms content ofthe hydrocarbon feed.

In some embodiments, the sulfur content of the crude product may be atmost 90%, at most 50%, at most 10%, or at most 5% of the sulfur contentof the crude product. In certain embodiments, the crude product has asulfur content of at least 1%, at least 30%, at least 80%, or at least99% of the sulfur content of the hydrocarbon feed. In some embodiments,the sulfur content of the crude product is 70-130%, 80-120%, or 90-110%of the sulfur content of the hydrocarbon feed.

In some embodiments, total nitrogen content of the crude product may beat most 90%, at most 80%, at most 10%, or at most 5% of a total nitrogencontent of the hydrocarbon feed. In certain embodiments, the crudeproduct has a total nitrogen content of at least 1%, at least 30%, atleast 80%, or at least 99% of the total nitrogen content of thehydrocarbon feed.

In some embodiments, basic nitrogen content of the crude product may atmost 95%, at most 90%, at most 50%, at most 10%, or at most 5% of thebasic nitrogen content of the hydrocarbon feed. In certain embodiments,the crude product has a basic nitrogen content of at least 1%, at least30%, at least 80%, or at least 99% of the basic nitrogen content of thehydrocarbon feed.

In some embodiments, the oxygen content of the crude product may be atmost 90%, at most 50%, at most 30%, at most 10%, or at most 5% of theoxygen content of the hydrocarbon feed. In certain embodiments, thecrude product has a oxygen content of at least 1%, at least 30%, atleast 80%, or at least 99% of the oxygen content of the hydrocarbonfeed. In some embodiments, the total content of carboxylic acidcompounds of the crude product may be at most 90%, at most 50%, at most10%, at most 5% of the content of the carboxylic acid compounds in thehydrocarbon feed. In certain embodiments, the crude product has a totalcontent of carboxylic acid compounds of at least 1%, at least 30%, atleast 80%, or at least 99% of the total content of carboxylic acidcompounds in the hydrocarbon feed.

In some embodiments, selected organic oxygen compounds may be reduced inthe hydrocarbon feed. In some embodiments, carboxylic acids and/or metalsalts of carboxylic acids may be chemically reduced beforenon-carboxylic containing organic oxygen compounds. Carboxylic acids andnon-carboxylic containing organic oxygen compounds in a crude productmay be differentiated through analysis of the crude product usinggenerally known spectroscopic methods (for example, infrared analysis,mass spectrometry, and/or gas chromatography).

The crude product, in certain embodiments, has an oxygen content of atmost 90%, at most 80%, at most 70%, or at most 50% of the oxygen contentof the hydrocarbon feed, and TAN of the crude product is at most 90%, atmost 70%, at most 50%, or at most 40% of the TAN of the hydrocarbonfeed. In certain embodiments, the crude product has an oxygen content ofat least 1%, at least 30%, at least 80%, or at least 99% of the oxygencontent of the hydrocarbon feed, and the crude product has a TAN of atleast 1%, at least 30%, at least 80%, or at least 99% of the TAN of thehydrocarbon feed.

Additionally, the crude product may have a content of carboxylic acidsand/or metal salts of carboxylic acids of at most 90%, at most 70%, atmost 50%, or at most 40% of the hydrocarbon feed, and a content ofnon-carboxylic containing organic oxygen compounds within 70-130%,80-120%, or 90-110% of the non-carboxylic containing organic oxygencompounds of the hydrocarbon feed.

In some embodiments, the crude product includes, in its molecularstructures, from 0.05-0.15 grams or from 0.09-0.13 grams of hydrogen pergram of crude product. The crude product may include, in its molecularstructure, from 0.8-0.9 grams or from 0.82-0.88 grams of carbon per gramof crude product. A ratio of atomic hydrogen to atomic carbon (H/C) ofthe crude product may be within 70-130%, 80-120%, or 90-110% of theatomic H/C ratio of the hydrocarbon feed. A crude product atomic H/Cratio within 10-30% of the hydrocarbon feed atomic H/C ratio indicatesthat uptake and/or consumption of hydrogen in the process is relativelysmall, and/or that hydrogen is produced in situ.

The crude product includes components with a range of boiling points. Insome embodiments, the crude product includes, per gram of the crudeproduct: at least 0.001 grams, or from 0.001-0.5 grams of hydrocarbonswith a boiling range distribution of at most 100° C. at 0.101 MPa; atleast 0.001 grams, or from 0.001-0.5 grams of hydrocarbons with aboiling range distribution between 100° C. and 200° C. at 0.101 MPa; atleast 0.001 grams, or from 0.001-0.5 grams of hydrocarbons with aboiling range distribution between 200° C. and 300° C. at 0.101 MPa; atleast 0.001 grams, or from 0.001-0.5 grams of hydrocarbons with aboiling range distribution between 300° C. and 400° C. at 0.101 MPa; andat least 0.001 grams, or from 0.001-0.5 grams of hydrocarbons with aboiling range distribution between 400° C. and 538° C. at 0.101 MPa.

In some embodiments the crude product includes, per gram of crudeproduct, at least 0.001 grams of hydrocarbons with a boiling rangedistribution of at most 100° C. at 0.101 MPa and/or at least 0.001 gramsof hydrocarbons with a boiling range distribution between 100° C. and200° C. at 0.101 MPa.

In some embodiments, the crude product may have at least 0.001 grams, orat least 0.01 grams of naphtha per gram of crude product. In otherembodiments, the crude product may have a naphtha content of at most 0.6grams, or at most 0.8 grams of naphtha per gram of crude product.

In some embodiments, the crude product has a distillate content of70-130%, 80-120%, or 90-110% of the distillate content of thehydrocarbon feed. The distillate content of the crude product may be,per gram of crude product, in a range from 0.00001-0.5 grams, 0.001-0.3grams, or 0.002-0.2 grams.

In certain embodiments, the crude product has a VGO content of 70-130%,80-120%, or 90-110% of the VGO content of the hydrocarbon feed. In someembodiments, the crude product has, per gram of crude product, a VGOcontent in a range from 0.00001-0.8 grams, 0.001-0.5 grams, 0.002-0.4grams, or 0.001-0.3 grams.

In some embodiments, the crude product has a residue content of at most90%, at most 80%, at most 50%, at most 30%, at most 20%, at most 10%, orat most 3% of the residue content of the hydrocarbon feed. In certainembodiments, the crude product has a residue content of 70-130%,80-120%, or 90-110% of the residue content of the hydrocarbon feed. Thecrude product may have, per gram of crude product, a residue content ina range from 0.00001-0.8 grams, 0.0001-0.5 grams, 0.0005-0.4 grams,0.001-0.3 grams, 0.005-0.2 grams, or 0.01-0.1 grams.

In some embodiments, the crude product has a total C₅ and C₇ asphaltenescontent of at most 90%, at most 50%, at most 30%, or at most 10% of thetotal C₅ and C₇ asphaltenes content of the hydrocarbon feed. In certainembodiments, the hydrocarbon feed has, per gram of hydrocarbon feed, atotal C₅ and C₇ asphaltenes content ranging from 0.001 grams to 0.2grams, 0.01 to 0.15 grams, or 0.05 grams to 0.1 grams.

In certain embodiments, the crude product has a MCR content of 70-130%,80-120%, or 90-110% of the MCR content of the hydrocarbon feed, whilethe crude product has a C₅ asphaltenes content of at most 90%, at most80%, or at most 50% of the C₅ asphaltenes content of the hydrocarbonfeed. In certain embodiments, the C₅ asphaltenes content of thehydrocarbon feed is at least 10%, at least 60%, or at least 70% of theC₅ asphaltenes content of the hydrocarbon feed while the MCR content ofthe crude product is within 10-30% of the MCR content of the hydrocarbonfeed. In some embodiments, decreasing the C₅ asphaltenes content of thehydrocarbon feed while maintaining a relatively stable MCR content mayincrease the stability of the hydrocarbon feed/total product mixture.

In some embodiments, the C₅ asphaltenes content and MCR content may becombined to produce a mathematical relationship between the highviscosity components in the crude product relative to the high viscositycomponents in the hydrocarbon feed. For example, a sum of a hydrocarbonfeed C₅ asphaltenes content and a hydrocarbon feed MCR content may berepresented by S. A sum of a crude product C₅ asphaltenes content and acrude product MCR content may be represented by S′. The sums may becompared (S′ to S) to assess the net reduction in high viscositycomponents in the hydrocarbon feed. S′ of the crude product may be in arange from 1-99%, 10-90%, or 20-80% of S. In some embodiments, a ratioof MCR content of the crude product to C₅ asphaltenes content is in arange from 1.0-3.0, 1.2-2.0, or 1.3-1.9.

In certain embodiments, the crude product has an MCR content that is atmost 90%, at most 80%, at most 50%, or at most 10% of the MCR content ofthe hydrocarbon feed. The crude product has, in some embodiments, from0.0001-0.1 grams, 0.005-0.08 grams, or 0.01-0.05 grams of MCR per gramof crude product. In some embodiments, the crude product includes fromgreater than 0 grams, but less than 0.01 grams, 0.000001-0.001 grams, or0.00001-0.0001 grams of total catalyst per gram of crude product. Thecatalyst may assist in stabilizing the crude product duringtransportation and/or treatment. The catalyst may inhibit corrosion,inhibit friction, and/or increase water separation abilities of thecrude product. Methods described herein may be configured to add one ormore catalysts described herein to the crude product during treatment.

The crude product produced from contacting system 100 has propertiesdifferent than properties of the hydrocarbon feed. Such properties mayinclude, but are not limited to: a) reduced TAN; b) reduced viscosity;c) reduced total Ni/V/Fe content; d) reduced content of sulfur, oxygen,nitrogen, or combinations thereof; e) reduced residue content; f)reduced content of C₅ and C₇ asphaltenes; g) reduced MCR content; h)increased API gravity; i) a reduced content of metals in metal salts oforganic acids; j) reduced basic nitrogen content; or k) combinationsthereof. In some embodiments, one or more properties of the crudeproduct, relative to the hydrocarbon feed, may be selectively changedwhile other properties are not changed as much, or do not substantiallychange. For example, it may be desirable to only selectively reduce oneor more components (for example, residue and/or viscosity) in ahydrocarbon feed without significantly changing the amount of Ni/V/Fe inthe hydrocarbon feed. In this manner, hydrogen uptake during contactingmay be “concentrated” on residue reduction, and not reduction of othercomponents. Since less of such hydrogen is also being used to reduceother components in the hydrocarbon feed, the amount of hydrogen usedduring the process may be minimized. For example, a disadvantaged crudemay have a high residue, but a Ni/V/Fe content that is acceptable tomeet treatment and/or transportation specifications. Such hydrocarbonfeed may be more efficiently treated by reducing residue without alsoreducing Ni/V/Fe.

Catalysts used in one or more embodiments of the inventions may includeone or more bulk metals and/or one or more metals on a support. Themetals may be in elemental form or in the form of a compound of themetal. The catalysts described herein may be introduced into thecontacting zone as a precursor, and then become active as a catalyst inthe contacting zone (for example, when sulfur and/or a hydrocarbon feedcontaining sulfur is contacted with the precursor). The catalyst orcombination of catalysts used as described herein may or may not becommercial catalysts. Examples of commercial catalysts that arecontemplated to be used as described herein include HDS3; HDS22; HDN60;C234; C311; C344; C411; C424; C344; C444; C447; C454; C448; C524; C534;DC2531; DN120; DN130; DN140; DN190; DN200; DN800; DN2118; DN2318;DN3100; DN3110; DN3300; DN3310; DN3330; RC400; RC410; RN412; RN400;RN420; RN440; RN450; RN650; RN5210; RN5610; RN5650; RM430; RM5030; Z603;Z623; Z673: Z703; Z713; Z723; Z753; and Z763, which are available fromCRI International, Inc. (Houston, Tex., U.S.A.).

In some embodiments, catalysts used to change properties of thehydrocarbon feed include one or more Columns 5-10 metals on a support.Columns 5-10 metal(s) include, but are not limited to, vanadium,chromium, molybdenum, tungsten, manganese, technetium, rhenium, iron,cobalt, nickel, ruthenium, palladium, rhodium, osmium, iridium,platinum, or mixtures thereof. The catalyst may have, per gram ofcatalyst, a total Columns 5-10 metal(s) content in a range from at least0.0001 grams, at least 0.001 grams, at least 0.01 grams, or in a range0.0001-0.6 grams, 0.001-0.3 grams, 0.005-0.1 grams, or 0.01-0.08 grams.In some embodiments, the catalyst includes Column 15 element(s) inaddition to the Columns 5-10 metal(s). Examples of Column 15 elementsinclude phosphorus. The catalyst may have a total Column 15 elementcontent, per gram of catalyst, in range from 0.000001-0.1 grams,0.00001-0.06 grams, 0.00005-0.03 grams, or 0.0001-0.001 grams.

In certain embodiments, the catalyst includes Column 6 metal(s). Thecatalyst may have, per gram of catalyst, a total Column 6 metal(s)content of at least 0.00001, at least 0.01 grams, at least 0.02 gramsand/or in a range from 0.0001-0.6 grams, 0.001-0.3 grams, 0.005-0.1grams, or 0.01-0.08 grams. In some embodiments, the catalyst includesfrom 0.0001-0.06 grams of Column 6 metal(s) per gram of catalyst. Insome embodiments, the catalyst includes Column 15 element(s) in additionto the Column 6 metal(s).

In some embodiments, the catalyst includes a combination of Column 6metal(s) with one or more metals from Column 5 and/or Columns 7-10. Amolar ratio of Column 6 metal to Column 5 metal may be in a range from0.1-20, 1-10, or 2-5. A molar ratio of Column 6 metal to Columns 7-10metal may be in a range from 0.1-20, 1-10, or 2-5. In some embodiments,the catalyst includes Column 15 element(s) in addition to thecombination of Column 6 metal(s) with one or more metals from Columns 5and/or 7-10. In other embodiments, the catalyst includes Column 6metal(s) and Column 10 metal(s). A molar ratio of the total Column 10metal to the total Column 6 metal in the catalyst may be in a range from1-10, or from 2-5. In certain embodiments, the catalyst includes Column5 metal(s) and Column 10 metal(s). A molar ratio of the total Column 10metal to the total Column 5 metal in the catalyst may be in a range from1-10, or from 2-5.

In some embodiments, Columns 5-10 metal(s) are incorporated in, ordeposited on, a support to form the catalyst. In certain embodiments,Columns 5-10 metal(s) in combination with Column 15 element(s) areincorporated in, or deposited on, the support to form the catalyst. Inembodiments in which the metal(s) and/or element(s) are supported, theweight of the catalyst includes all support, all metal(s), and allelement(s). The support may be porous and may include refractory oxides,porous carbon based materials, zeolites, or combinations thereof.Refractory oxides may include, but are not limited to, alumina, silica,silica-alumina, titanium oxide, zirconium oxide, magnesium oxide, ormixtures thereof. Supports may be obtained from a commercialmanufacturer such as Criterion Catalysts and Technologies LP (Houston,Tex., U.S.A.). Porous carbon based materials include, but are notlimited to, activated carbon and/or porous graphite. Examples ofzeolites include Y-zeolites, beta zeolites, mordenite zeolites, ZSM-5zeolites, and ferrierite zeolites. Zeolites may be obtained from acommercial manufacturer such as Zeolyst (Valley Forge, Pa., U.S.A.).

The support, in some embodiments, is prepared such that the support hasan average pore diameter of at least 150 Å, at least 170 Å, or at least180 Å. In certain embodiments, a support is prepared by forming anaqueous paste of the support material. In some embodiments, an acid isadded to the paste to assist in extrusion of the paste. The water anddilute acid are added in such amounts and by such methods as required togive the extrudable paste a desired consistency. Examples of acidsinclude, but are not limited to, nitric acid, acetic acid, sulfuricacid, and hydrochloric acid.

The paste may be extruded and cut using generally known catalystextrusion methods and catalyst cutting methods to form extrudates. Theextrudates may be heat treated at a temperature in a range from 65-260°C. or from 85-235° C. for a period of time (for example, for 0.5-8hours) and/or until the moisture content of the extrudate has reached adesired level. The heat treated extrudate may be further heat treated ata temperature in a range from 800-1200° C. or 900-1100° C.) to form thesupport having an average pore diameter of at least 150 Å.

In certain embodiments, the support includes gamma alumina, thetaalumina, delta alumina, alpha alumina, or combinations thereof. Theamount of gamma alumina, delta alumina, alpha alumina, or combinationsthereof, per gram of catalyst support, may be in a range from0.0001-0.99 grams, 0.001-0.5 grams, 0.01-0.1 grams, or at most 0.1 gramsas determined by x-ray diffraction. In some embodiments, the supporthas, either alone or in combination with other forms of alumina, a thetaalumina content, per gram of support, in a range from 0.1-0.99 grams,0.5-0.9 grams, or 0.6-0.8 grams, as determined by x-ray diffraction. Insome embodiments, the support may have at least 0.1 grams, at least 0.3grams, at least 0.5 grams, or at least 0.8 grams of theta alumina, asdetermined by x-ray diffraction.

Supported catalysts may be prepared using generally known catalystpreparation techniques. Examples of catalyst preparations are describedin U.S. Pat. Nos. 6,919,018 to Bhan; 6,759,364 to Bhan; 6,218,333 toGabrielov et al.; 6,290,841 to Gabrielov et al.; and 5,744,025 to Boonet al.

In some embodiments, the support may be impregnated with metal to form acatalyst. In certain embodiments, the support is heat treated attemperatures in a range from 400-1200° C., 450-1000° C., or 600-900° C.prior to impregnation with a metal. In some embodiments, impregnationaids may be used during preparation of the catalyst. Examples ofimpregnation aids include a citric acid component,ethylenediaminetetraacetic acid (EDTA), ammonia, or mixtures thereof.

In certain embodiments, a catalyst may be formed by adding orincorporating the Columns 5-10 metal(s) to heat treated shaped mixturesof support (“overlaying”). Overlaying a metal on top of the heat treatedshaped support having a substantially or relatively uniformconcentration of metal often provides beneficial catalytic properties ofthe catalyst. Heat treating of a shaped support after each overlay ofmetal tends to improve the catalytic activity of the catalyst. Methodsto prepare a catalyst using overlay methods are described in U.S. Pat.No. 6,759,364 to Bhan.

The Columns 5-10 metal(s) and support may be mixed with suitable mixingequipment to form a Columns 5-10 metal(s)/support mixture. The Columns5-10 metal(s)/support mixture may be mixed using suitable mixingequipment. Examples of suitable mixing equipment include tumblers,stationary shells or troughs, Muller mixers (for example, batch type orcontinuous type), impact mixers, and any other generally known mixer, orgenerally known device, that will suitably provide the Columns 5-10metal(s)/support mixture. In certain embodiments, the materials aremixed until the Columns 5-10 metal(s) is (are) substantiallyhomogeneously dispersed in the support.

In some embodiments, the catalyst is heat treated at temperatures from150-750° C., from 200-740° C., or from 400-730° C. after combining thesupport with the metal.

In some embodiments, the catalyst may be heat treated in the presence ofhot air and/or oxygen rich air at a temperature in a range between 400°C. and 1000° C. to remove volatile matter such that at least a portionof the Columns 5-10 metals are converted to the corresponding metaloxide.

In other embodiments, however, the catalyst may be heat treated in thepresence of air at temperatures in a range from 35° C. to 500° C., from100° C. to 400° C., or from 150° C. to 300° C. for a period of time in arange from 1-3 hours to remove a majority of the volatile componentswithout converting the Columns 5-10 metals to the metal oxide. Catalystsprepared by such a method are generally referred to as “uncalcined”catalysts or “dried”. When catalysts are prepared in this manner incombination with a sulfiding method, the active metals may besubstantially dispersed in the support. Preparations of uncalcinedcatalysts are described in U.S. Pat. Nos. 6,218,333 to Gabrielov et al.,and 6,290,841 to Gabrielov et al.

In certain embodiments, a theta alumina support may be combined withColumns 5-10 metals to form a theta alumina support/Columns 5-10 metalsmixture. The theta alumina support/Columns 5-10 metals mixture may beheat treated at a temperature of at least 400° C. to form the catalysthaving a pore size distribution with a median pore diameter of at least230 Å. Typically, such heat treating is conducted at temperatures of atmost 1200° C.

In some embodiments, the support (either a commercial support or asupport prepared as described herein) may be combined with a supportedcatalyst and/or a bulk metal catalyst. In some embodiments, thesupported catalyst may include Column 15 metal(s). For example, thesupported catalyst and/or the bulk metal catalyst may be crushed into apowder with an average particle size from 1-50 microns, 2-45 microns, or5-40 microns. The powder may be combined with support to form anembedded metal catalyst. In some embodiments, the powder may be combinedwith the support and then extruded using standard techniques to form acatalyst having a pore size distribution with a median pore diameter ina range from 80-200 Å or 90-180 Å, or 120-130 Å.

Combining the catalyst with the support allows, in some embodiments, atleast a portion of the metal to reside under the surface of the embeddedmetal catalyst (for example, embedded in the support), leading to lessmetal on the surface than would otherwise occur in the unembedded metalcatalyst. In some embodiments, having less metal on the surface of thecatalyst extends the life and/or catalytic activity of the catalyst byallowing at least a portion of the metal to move to the surface of thecatalyst during use. The metals may move to the surface of the catalystthrough erosion of the surface of the catalyst during contact of thecatalyst with a hydrocarbon feed.

In some embodiments, the catalyst is prepared by combining one or moreColumns 6-10 metal(s), mineral oxides having a particle size of at most500 micrometers, and a support. The mineral oxides may include, alumina,silica, silica-alumina, titanium oxide, zirconium oxide, magnesiumoxide, or mixtures thereof. The mineral oxides may be obtained from anextrudate process to produce support. For example, alumina fines can beobtained from an alumina extrudate production to produce catalystsupports. In some embodiments, mineral oxide fines may have a particlesize of at most 500 micrometers, at most 150 micrometers, at most 100micrometers, or at most 75 micrometers. The particle size of the mineraloxides may range from 0.2 micrometers to 500 micrometers, 0.3micrometers to 100 micrometers, or 0.5 micrometers to 75 micrometers.Combining mineral oxides with one or more Columns 6-10 metal and asupport may allow less metal to reside on the surface of the catalyst.

Intercalation and/or mixing of the components of the catalysts changes,in some embodiments, the structured order of the Column 6 metal in theColumn 6 oxide crystal structure to a substantially random order ofColumn 6 metal in the crystal structure of the embedded catalyst. Theorder of the Column 6 metal may be determined using powder x-raydiffraction methods. The order of elemental metal in the catalystrelative to the order of elemental metal in the metal oxide may bedetermined by comparing the order of the Column 6 metal peak in an x-raydiffraction spectrum of the Column 6 oxide to the order of the Column 6metal peak in an x-ray diffraction spectrum of the catalyst. Frombroadening and/or absence of patterns associated with Column 6 metal inan x-ray diffraction spectrum, it is possible to estimate that theColumn 6 metal(s) are substantially randomly ordered in the crystalstructure.

For example, molybdenum trioxide and the alumina support having a medianpore diameter of at least 180 Å may be combined to form analumina/molybdenum trioxide mixture. The molybdenum trioxide has adefinite pattern (for example, definite D₀₀₁, D₀₀₂ and/or D₀₀₃ peaks).The alumina/Column 6 trioxide mixture may be heat treated at atemperature of at least 538° C. (1000° F.) to produce a catalyst thatdoes not exhibit a pattern for molybdenum dioxide in an x-raydiffraction spectrum (for example, an absence of the D₀₀₁ peak).

In some embodiments, the catalyst may be prepared by combining asupported catalyst and/or a used catalyst with a support and one or moreColumns 6-10 metals to produce the catalyst. In some embodiments, theColumns 6-10 metals (for example, molybdenum oxides and/or tungstenoxides) have a particle size of at most 500 micrometers, at most 150micrometers, at most 100 micrometers, or at most 75 micrometers. Theparticle size of the Columns 6-10 metals may range from 0.1 micrometersto 500 micrometers, 1 micrometers to 100 micrometers, or 10 micrometersto 75 micrometers. In some embodiments, at least 50 percent of theparticles have a particle size between 2 micrometers to 15 micrometers.The mixture of the used catalyst with a support and one or more Columns6-10 metals is dried at temperatures of at least 100° C. to remove anylow boiling components and then heated to at least 500° C., at least1000° C., at least 1200° C. or at least 1300° C. to convert the Columns6-10 metals to metal oxides. The median pore diameter of the catalystmay range from 50 Å to 150 Å, 60 Å to 140 Å, or 70 Å to 130 Å.

The catalyst may include at least 0.01 grams, at least 0.1 grams, or atleast 0.2 grams of used catalyst per gram of catalyst and at most 0.3grams, at most 0.2 grams, or at most 0.1 grams of Columns 6-10 metal(s).In some embodiments, the catalyst includes from 0.001 grams to 0.3grams, from 0.05 to 0.2 grams, or from 0.01 grams to 0.1 grams of usedcatalyst, per gram of catalyst. In certain embodiments, the ultrastablecatalyst includes from 0.001 grams to 0.2 grams or 0.01 grams to 0.1grams of Column 6 metal(s). In some embodiments, the ultrastablecatalyst may include from 0.001 grams to 0.1 grams, 0.005 to 0.05 grams,or from 0.01 grams to 0.03 grams of Column 10 metal(s). In certainembodiments, the ultrastable catalyst may include from 0.001 grams to0.1 grams, 0.005 grams to 0.05 grams, or from 0.01 grams to 0.03 gramsof Column 9 metal(s). In some embodiments, the ultrastable catalystincludes from 0.0001 to 0.01 grams, 0.0005 grams to 0.005 grams, or0.0008 to 0.003 grams of Column 15 element(s).

The catalyst, after sulfiding, when analyzed using scanning electronmicroscopy, exhibits a significantly lower degree of molybdenumdisulfide (MoS₂) slab stacking with the stacks having reduced heightsand length as compared to alternative molybdenum-containinghydroprocessing catalysts. Preparation of such catalysts are describedin U.S. patent applications entitled “A Catalyst and Process for theManufacture of Ultra-Low Sulfur Distillate Product” and “A Highly StableHeavy Hydrocarbon Hydrodesulfurization Catalyst and Method of Making andUse Thereof” to Bhan.

In commercial applications, after sulfidation of the hydroprocessingcatalysts, the hydroprocessing catalysts are typically heated to 400° C.over one or more months to control the generation of hydrogen sulfide.Slowly heating of hydroprocessing catalysts may inhibit deactivation ofthe catalyst. The catalyst described herein has enhanced stability inthe presence of hydrogen sulfide when heated to 400° C. in less thanthree weeks. Being able to preheat the catalyst over a shorter period oftime may increase the amount of hydrocarbon feed that can be processedthrough a contacting system.

In some embodiments, catalysts may be characterized by pore structure.Various pore structure parameters include, but are not limited to, porediameter, pore volume, surface areas, or combinations thereof. Thecatalyst may have a distribution of total quantity of pore sizes versuspore diameters. The median pore diameter of the pore size distributionmay be in a range from 30-1000 Å, 50-500 Å, or 60-300 Å. In someembodiments, catalysts that include at least 0.5 grams of gamma aluminaper gram of catalyst have a pore size distribution with a median porediameter in a range from 50 to 200 Å; 90 to 180 Å, 100 to 140 Å, or 120to 130 Å. In some embodiments, the gamma alumina catalyst has a poresize distribution with a median pore diameter ranging from 50 Å to 150Å, from 60 Å to 135 Å, or from 70 Å to 120 Å. In other embodiments,catalysts that include at least 0.1 grams of theta alumina per gram ofcatalyst have a pore size distribution with a median pore diameter in arange from 180-500 Å, 200-300 Å, or 230-250 Å. In some embodiments, themedian pore diameter of the pore size distribution is at least 120 Å, atleast 150 Å, at least 180 Å, at least 200 Å, at least 220 Å, at least230 Å, or at least 300 Å. Such median pore diameters are typically atmost 1000 Å.

The catalyst may have a pore size distribution with a median porediameter of at least 60 Å or at least 90 Å. In some embodiments, thecatalyst has a pore size distribution with a median pore diameter in arange from 90-180 Å, 100-140 Å, or 120-130 Å, with at least 60% of atotal number of pores in the pore size distribution having a porediameter within 45 Å, 35 Å, or 25 Å of the median pore diameter. Incertain embodiments, the catalyst has a pore size distribution with amedian pore diameter in a range from 70-180 Å, with at least 60% of atotal number of pores in the pore size distribution having a porediameter within 45 Å, 35 Å, or 25 Å of the median pore diameter.

In embodiments in which the median pore diameter of the pore sizedistribution is at least 180 Å, at least 200 Å, or at least 230 Å,greater that 60% of a total number of pores in the pore sizedistribution have a pore diameter within 50 Å, 70 Å, or 90 Å of themedian pore diameter. In some embodiments, the catalyst has a pore sizedistribution with a median pore diameter in a range from 180-500 Å,200-400 Å, or 230-300 Å, with at least 60% of a total number of pores inthe pore size distribution having a pore diameter within 50 Å, 70 Å, or90 Å of the median pore diameter.

In some embodiments, pore volume of pores may be at least 0.3 cm³/g, atleast 0.7 cm³/g, or at least 0.9 cm³/g. In certain embodiments, porevolume of pores may range from 0.3-0.99 cm³/g, 0.4-0.8 cm³/g, or 0.5-0.7cm³/g.

The catalyst having a pore size distribution with a median pore diameterin a range from 50-180 Å may, in some embodiments, have a surface areaof at least 100 m²/g, at least 120 m²/g, at least 170 m²/g, at least220, or at least 270 m²/g. Such surface area may be in a range from100-300 m²/g, 120-270 m²/g, 130-250 m²/g, or 170-220 m²/g.

In certain embodiments, the catalyst having a pore size distributionwith a median pore diameter in a range from 180-300 Å may have a surfacearea of at least 60 m²/g, at least 90 m²/g, least 100 m²/g, at least 120m²/g, or at least 270 m²/g. Such surface area may be in a range from60-300 m²/g, 90-280 m²/g, 100-270 m²/g, or 120-250 m²/g.

In some embodiments, the catalyst is characterized using Ramanspectroscopy. The catalyst that includes theta alumina and metals fromColumns 6-10 may exhibit bands in a region between 800 cm⁻¹ and 900cm⁻¹. Bands observed in the 800 cm⁻¹ to 900 cm⁻¹ region may beattributed to Metal-Oxygen-Metal antisymmetric stretching. In someembodiments, the catalyst that includes theta alumina and Column 6metals exhibits bands near 810 cm⁻¹, near 835 cm⁻¹, and 880 cm⁻¹. Insome embodiments, the Raman shift of a molybdenum catalyst at thesebands may indicate that the catalyst includes a species intermediatebetween Mo₇O₂₄ ⁶⁻ and MO₄ ²⁻. In some embodiments, the intermediatespecies is crystalline.

In some embodiments, the catalyst that includes metals from Columns 5may exhibit bands in a region between 650 cm⁻¹ and 1000 cm⁻¹. Bandsobserved near 650 cm⁻¹ and 1000 cm⁻¹ may be attributed to V═O motions.In some embodiments, the catalyst that includes theta alumina andColumns 5 and 6 metals exhibits bands near 670 cm⁻¹ and 990 cm⁻¹.

In certain embodiments, the catalyst exists in shaped forms, forexample, pellets, cylinders, and/or extrudates. The catalyst typicallyhas a flat plate crush strength in a range from 50-500 N/cm, 60-400N/cm, 100-350 N/cm, 200-300 N/cm, or 220-280 N/cm.

In some embodiments, the catalyst and/or the catalyst precursor issulfided to form metal sulfides (prior to use) using techniques known inthe art (for example, ACTICAT™ process, CRI International, Inc.). Insome embodiments, the catalyst may be dried then sulfided.Alternatively, the catalyst may be sulfided in situ by contact of thecatalyst with a hydrocarbon feed that includes sulfur-containingcompounds. In-situ sulfurization may utilize either gaseous hydrogensulfide in the presence of hydrogen, or liquid-phase sulfurizing agentssuch as organosulfur compounds (including alkylsulfides, polysulfides,thiols, and sulfoxides). Ex-situ sulfurization processes are describedin U.S. Pat. Nos. 5,468,372 to Seamans et al., and 5,688,736 to Seamanset al.

In certain embodiments, a first type of catalyst (“first catalyst”)includes Columns 5-10 metal(s) in combination with a support, and has apore size distribution with a median pore diameter in a range from150-250 Å. The first catalyst may have a surface area of at least 100m²/g. The pore volume of the first catalyst may be at least 0.5 cm³/g.The first catalyst may have a gamma alumina content of at least 0.5grams of gamma alumina, and typically at most 0.9999 grams of gammaalumina, per gram of first catalyst. The first catalyst has, in someembodiments, a total content of Column 6 metal(s), per gram of catalyst,in a range from 0.0001 to 0.1 grams. The first catalyst is capable ofremoving a portion of the Ni/V/Fe from a hydrocarbon feed, removing aportion of the components that contribute to TAN of a hydrocarbon feed,removing at least a portion of the C₅ asphaltenes from a hydrocarbonfeed, removing at least a portion of the metals in metal salts oforganic acids in the hydrocarbon feed, or combinations thereof. Otherproperties (for example, sulfur content, VGO content, API gravity,residue content, or combinations thereof) may exhibit relatively smallchanges when the hydrocarbon feed is contacted with the first catalyst.Being able to selectively change properties of a hydrocarbon feed whileonly changing other properties in relatively small amounts may allow thehydrocarbon feed to be more efficiently treated. In some embodiments,one or more first catalysts may be used in any order.

In certain embodiments, the second type of catalyst (“second catalyst”)includes Columns 5-10 metal(s) in combination with a support, and has apore size distribution with a median pore diameter in a range from 90 Åto 180 Å. At least 60% of the total number of pores in the pore sizedistribution of the second catalyst have a pore diameter within 45 Å ofthe median pore diameter. Contact of the hydrocarbon feed with thesecond catalyst under suitable contacting conditions may produce a crudeproduct that has selected properties (for example, TAN) significantlychanged relative to the same properties of the hydrocarbon feed whileother properties are only changed by a small amount. A hydrogen source,in some embodiments, may be present during contacting.

The second catalyst may reduce at least a portion of the components thatcontribute to the TAN of the hydrocarbon feed, at least a portion of thecomponents that contribute to relatively high viscosities, and reduce atleast a portion of the Ni/V/Fe content of the crude feed. Additionally,contact of hydrocarbon feeds with the second catalyst may produce acrude product with a relatively small change in the sulfur contentrelative to the sulfur content of the hydrocarbon feed. For example, thecrude product may have a sulfur content of 70%-130% of the sulfurcontent of the hydrocarbon feed. The crude product may also exhibitrelatively small changes in distillate content, VGO content, and residuecontent relative to the hydrocarbon feed.

In some embodiments, the hydrocarbon feed may have a relatively lowcontent of Ni/V/Fe (for example, at most 50 wtppm), but a relativelyhigh TAN, asphaltenes content, or content of metals in metal salts oforganic acids. A relatively high TAN (for example, TAN of at least 0.3)may render the hydrocarbon feed unacceptable for transportation and/orrefining. A disadvantaged crude with a relatively high C₅ asphaltenescontent may exhibit less stability during processing relative to othercrudes with relatively low C₅ asphaltenes content. Contact of thehydrocarbon feed with the second catalysts, may remove acidic componentsand/or C₅ asphaltenes contributing to TAN from the hydrocarbon feed. Insome embodiments, reduction of C₅ asphaltenes and/or componentscontributing to TAN may reduce the viscosity of the hydrocarbonfeed/total product mixture relative to the viscosity of the hydrocarbonfeed. In certain embodiments, one or more combinations of secondcatalysts may enhance stability of the total product/crude productmixture, increase catalyst life, allow minimal net hydrogen uptake bythe hydrocarbon feed, or combinations thereof, when used to treathydrocarbon feed as described herein.

In some embodiments, a third type of catalyst (“third catalyst”) may beobtainable by combining a support with Column 6 metal(s) to produce acatalyst precursor. The catalyst precursor may be heated in the presenceof one or more sulfur containing compounds at a temperature below 500°C. (for example, below 482° C.) for a relatively short period of time toform the uncalcined third catalyst. Typically, the catalyst precursor isheated to at least 100° C. for 2 hours. In certain embodiments, thethird catalyst may, per gram of catalyst, have a Column 15 elementcontent in a range from 0.001-0.03 grams, 0.005-0.02 grams, or0.008-0.01 grams. The third catalyst may exhibit significant activityand stability when used to treat the hydrocarbon feed as describedherein. In some embodiments, the catalyst precursor is heated attemperatures below 500° C. in the presence of one or more sulfurcompounds.

The third catalyst may reduce at least a portion of the components thatcontribute to the TAN of the hydrocarbon feed, reduce at least a portionof the metals in metal salts of organic acids, reduce a Ni/V/Fe contentof the crude product, and reduce the viscosity of the crude product.Additionally, contact of hydrocarbon feeds with the third catalyst mayproduce a crude product with a relatively small change in the sulfurcontent relative to the sulfur content of the hydrocarbon feed and withrelatively minimal net hydrogen uptake by the hydrocarbon feed. Forexample, a crude product may have a sulfur content of 70%-130% of thesulfur content of the hydrocarbon feed. The crude product produced usingthe third catalyst may also exhibit relatively small changes in APIgravity, distillate content, VGO content, and residue content relativeto the hydrocarbon feed. The ability to reduce the TAN, the metals inmetal salts of organic salts, the Ni/V/Fe content, and the viscosity ofthe crude product while also only changing by a small amount the APIgravity, distillate content, VGO content, and residue contents relativeto the hydrocarbon feed, may allow the crude product to be used by avariety of treatment facilities.

The third catalyst, in some embodiments, may reduce at least a portionof the MCR content of the hydrocarbon feed, while maintaininghydrocarbon feed/total product stability. In certain embodiments, thethird catalyst may have a Column 6 metal(s) content in a range from0.0001-0.1 grams, 0.005-0.05 grams, or 0.001-0.01 grams and a Column 10metal(s) content in a range from 0.0001-0.05 grams, 0.005-0.03 grams, or0.001-0.01 grams per gram of catalyst. A Columns 6 and 10 metal(s)catalyst may facilitate reduction of at least a portion of thecomponents that contribute to MCR in the hydrocarbon feed attemperatures in a range from 300-500° C. or 350-450° C. and pressures ina range from 0.1-10 MPa, 1-8 MPa, or 2-5 MPa.

In certain embodiments, a fourth type of catalyst (“fourth catalyst”)includes Column 5 metal(s) in combination with a theta alumina support.The fourth catalyst has a pore size distribution with a median porediameter of at least 180 Å. In some embodiments, the median porediameter of the fourth catalyst may be at least 220 Å, at least 230 Å,at least 250 Å, or at least 300 Å. The support may include at least 0.1grams, at least 0.5 grams, at least 0.8 grams, or at least 0.9 grams oftheta alumina per gram of support. The fourth catalyst may include, insome embodiments, at most 0.1 grams of Column 5 metal(s) per gram ofcatalyst, and at least 0.0001 grams of Column 5 metal(s) per gram ofcatalyst. In certain embodiments, the Column 5 metal is vanadium.

In some embodiments, the hydrocarbon feed may be contacted with anadditional catalyst subsequent to contact with the fourth catalyst. Theadditional catalyst may be one or more of the following: the firstcatalyst, the second catalyst, the third catalyst, the fifth catalyst,the sixth catalyst, the seventh catalyst, commercial catalysts describedherein, or combinations thereof.

In some embodiments, hydrogen may be generated during contacting of thehydrocarbon feed with the fourth catalyst at a temperature in a rangefrom 300-400° C., 320-380° C., or 330-370° C. The crude product producedfrom such contacting may have a TAN of at most 90%, at most 80%, at most50%, or at most 10% of the TAN of the hydrocarbon feed. Hydrogengeneration may be in a range from 1-50 Nm³/m³, 10-40 Nm³/m³, or 15-25Nm³/m³. The crude product may have a total Ni/V/Fe content of at most90%, at most 80%, at most 70%, at most 50%, at most 10%, or at least 1%of total Ni/V/Fe content of the hydrocarbon feed.

In certain embodiments, a fifth type of catalyst (“fifth catalyst”)includes Column 6 metal(s) in combination with a theta alumina support.The fifth catalyst has a pore size distribution with a median porediameter of at least 180 Å, at least 220 Å, at least 230 Å, at least 250Å, at least 300 Å, or at most 500 Å. The support may include at least0.1 grams, at least 0.5 grams, or at most 0.999 grams of theta aluminaper gram of support. In some embodiments, the support has an alphaalumina content of below 0.1 grams of alpha alumina per gram ofcatalyst. The catalyst includes, in some embodiments, at most 0.1 gramsof Column 6 metal(s) per gram of catalyst and at least 0.0001 grams ofColumn 6 metal(s) per gram of catalyst. In some embodiments, the Column6 metal(s) are molybdenum and/or tungsten.

In certain embodiments, net hydrogen uptake by the hydrocarbon feed maybe relatively low (for example, from 0.01-100 Nm³/m³) when thehydrocarbon feed is contacted with the fifth catalyst at a temperaturein a range from 310-400° C., from 320-370° C., or from 330-360° C. Nethydrogen uptake by the hydrocarbon feed may be in a range from 1-20Nm³/m³, 2-15 Nm³/m³, or 3-10 Nm³/m³. The crude product produced fromcontact of the hydrocarbon feed with the fifth catalyst may have a TANof at most 90%, at most 80%, at most 50%, or at most 10% of the TAN ofthe hydrocarbon feed. TAN of the crude product may be in a range from0.01-0.1, 0.03-0.05, or 0.02-0.03.

In certain embodiments, a sixth type of catalyst (“sixth catalyst”)includes Column 5 metal(s) and Column 6 metal(s) in combination with thetheta alumina support. The sixth catalyst has a pore size distributionwith a median pore diameter of at least 180 Å. In some embodiments, themedian pore diameter of pore size distribution may be at least 220 Å, atleast 230 Å, at least 250 Å, at least 300 Å, or at most 500 Å. Thesupport may include at least 0.1 grams, at least 0.5 grams, at least 0.8grams, at least 0.9 grams, or at most 0.99 grams of theta alumina pergram of support. The catalyst may include, in some embodiments, a totalof Column 5 metal(s) and Column 6 metal(s) of at most 0.1 grams per gramof catalyst, and at least 0.0001 grams of Column 5 metal(s) and Column 6metal(s) per gram of catalyst. In some embodiments, the molar ratio oftotal Column 6 metal to total Column 5 metal may be in a range from0.1-20, 1-10, or 2-5. In certain embodiments, the Column 5 metal isvanadium and the Column 6 metal(s) are molybdenum and/or tungsten.

When the hydrocarbon feed is contacted with the sixth catalyst at atemperature in a range from 310-400° C., from 320-370° C., or from330-360° C., net hydrogen uptake by the hydrocarbon feed may be in arange from −10 Nm³/m³ to 20 Nm³/m³, −7 Nm³/m³ to 10 Nm³/m³, or −5 Nm³/m³to 5 Nm³/m³. Negative net hydrogen uptake is one indication thathydrogen is being generated in situ. The crude product produced fromcontact of the hydrocarbon feed with the sixth catalyst may have a TANof at most 90%, at most 80%, at most 50%, at most 10%, or at least 1% ofthe TAN of the hydrocarbon feed. TAN of the crude product may be in arange from 0.01-0.1, 0.02-0.05, or 0.03-0.04.

Low net hydrogen uptake during contacting of the hydrocarbon feed withthe fourth, fifth, or sixth catalyst reduces the overall requirement ofhydrogen during processing while producing a crude product that isacceptable for transportation and/or treatment. Since producing and/ortransporting hydrogen is costly, minimizing the usage of hydrogen in aprocess decreases overall processing costs.

In some embodiments, contact of hydrocarbon feed with the fourthcatalyst, the fifth catalyst, the sixth catalyst or combinations thereofat a temperature in a range from 360° C. to 500° C., from 380° C. to480° C., from 400° C. to 470° C., or from 410° C. to 460° C., producesthe crude product with a residue content of at least 90%, at least 80%,at least 50%, at least 30% or at least 10% of the residue content of thehydrocarbon feed.

At elevated temperatures (for example greater than 360° C.), impuritiesand/or coke may form during contact of the hydrocarbon feed with one ormore catalysts. When contact is performed in a continuously stirredreactor, formation of impurities and/or coke may be determined bymeasuring an amount of sediment produced during contacting. In someembodiments, the content of sediment produced may be at most 0.002 gramsor at most 0.001 grams, per gram of hydrocarbon feed/total product. Whenthe content of sediment approaches 0.001 grams, adjustment of contactingconditions may be necessary to prevent shutdown of the process and/or tomaintain a suitable flow rate of hydrocarbon feed through the contactingzone. The sediment content may range, per gram of hydrocarbon feed/totalproduct, from 0.00001 grams to 0.03 grams, from 0.0001 grams to 0.02grams, from 0.001 to 0.01 grams. Contact of the crude product with thefourth catalyst, the fifth catalyst, the sixth catalyst, or combinationsthereof at elevated temperatures allows reduction of residue withminimal formation of sediment.

In certain embodiments, a seventh type of catalyst (“seventh catalyst”)has a total content of Column 6 metal(s) in a range from 0.0001-0.06grams of Column 6 metal(s) per gram of catalyst. The Column 6 metal ismolybdenum and/or tungsten. The seventh catalyst is beneficial inproducing a crude product that has a TAN of at most 90% of the TAN ofthe hydrocarbon feed.

In certain embodiments, an eighth type of catalyst (“eighth catalyst”)includes Columns 6-10 metal(s) in combination with a support, and has apore size distribution with a median pore diameter in a range from 50 Åto 180 Å. The eighth catalyst may have a surface area of at least 200m²/g. The pore volume of the eighth catalyst may be at least 0.5 cm³/g.The eighth catalyst may have a gamma alumina content of at least 0.5grams of gamma alumina, and typically at most 0.9999 grams of gammaalumina, per gram of eighth catalyst. The eighth catalyst has, in someembodiments, a total content of Column 6 metal(s), per gram of eighthcatalyst, in a range from 0.0001 grams to 0.1 grams, or from 0.01 gramsto 0.05 grams. The eighth catalyst is capable of removing a portion ofthe Ni/V/Fe and/or a portion of the molybdenum from the hydrocarbonfeed. In some embodiments, the eighth catalyst selectively removesorganometallic compounds (for example, vanadium, molybdenum, and/ornickel porphyrins) while only changing the amount of inorganic metalcompounds (for example, nickel oxides, nickel sulfide, vanadium oxidesand/or vanadium sulfides) by a relatively small amount. Theconcentration of organometallic compounds in a hydrocarbon feed may bemonitored by spectrophotometric methods as described by Yen in “The Roleof Trace Metals in Petroleum” (Ann Arbor Science Publishers, Inc. AnnArbor Mich., 1975, page 36). Removal of organometallic compounds mayenhance lives of catalysts positioned downstream of the eighth catalyst.

In some embodiments, a ninth type of catalyst (“ninth catalyst”)includes Columns 6-10 metal(s) in combination with a support and has apore size distribution with a median pore diameter in a range from 50 Åto 180 Å. The ninth catalyst support may include at least 0.01 grams, atleast 0.05 grams, or at least 0.1 grams of silica-alumina per gram ofninth catalyst. The ninth catalyst may have a Column 6 metal(s) contentin a range from 0.0001 to 0.3 grams, 0.005 grams to 0.2 grams, or 0.001grams to 0.1 grams and a Column 10 metal(s) content in a range from0.0001 grams to 0.05 grams, 0.005 grams to 0.03 grams, or 0.001 grams to0.01 grams per gram of ninth catalyst. In certain embodiments, the ninthcatalyst may, per gram of ninth catalyst, have a Column 15 elementcontent in a range from 0.001 grams to 0.03 grams, 0.005 grams to 0.02grams, or 0.008 grams to 0.01 grams. The ninth catalyst may facilitatereduction of at least a portion of the components that contribute toresidue, at least a portion of the C₅ and C₇ asphaltenes, and at least aportion of components that contribute to high viscosities in thehydrocarbon feed at temperatures in a range from 300° C. to 500° C.,350° C. to 450° C., or 370° C. to 430° C. and pressures in a range from0.1 to 8 MPa, 1 to 7 MPa, or 2 to 5 MPa. In some embodiments, the ninthcatalyst may reduce at least a portion of components that contribute tothe MCR content of the hydrocarbon feed, while maintaining hydrocarbonfeed/total product stability. In certain embodiments, the ninth catalystmay reduce at least a portion of the basic nitrogen components in ahydrocarbon feed at temperatures of at least 200° C. and pressures of atleast 3 MPa.

Contact of a hydrocarbon feed with the eighth and ninth catalyst attemperatures of at most 500° C. and pressure of at most 7 MPa mayproduce a crude product having a residue content, a total C₅ asphaltenesand C₇ asphaltenes content, and/or a viscosity of at most 90%, at most80%, at most 70%, at most 50%, at most 30% of the residue content, thetotal C₅ asphaltenes and C₇ asphaltenes content, and/or the viscosity ofthe hydrocarbon feed while maintaining a Ni/V/Fe content between 70% and130%, between 80% and 120%, or between 90 and 110% of the hydrocarbonfeed Ni/V/Fe content. In some embodiments, the viscosity of the crudeproduct is at most 99% of the viscosity of the hydrocarbon feed aftercontact with the eighth and ninth catalysts.

In some embodiments, a tenth type of catalyst (“tenth catalyst”)includes Columns 6-10 metal(s) in combination with a support and has apore size distribution with a median pore diameter in a range from 50 Åto 120 Å. The tenth catalyst support may include at least 0.01 grams, atleast 0.05 grams, at least 0.1 grams of silica-alumina per gram of tenthcatalyst. The tenth catalyst may have a Column 6 metal(s) content in arange from 0.0001 grams to 0.1 grams, 0.005 grams to 0.03 grams, or0.001 grams to 0.05 grams and a Column 10 metal(s) content in a rangefrom 0.0001 grams to 0.05 grams, 0.005 grams to 0.03 grams, or 0.001grams to 0.01 grams per gram of catalyst. The tenth catalyst mayfacilitate reduction of at least a portion of the components thatcontribute to residue, at least a portion of the C₅ and C₇ asphaltenes,and at least a portion of components that contribute to high viscositiesin the hydrocarbon feed. In some embodiments, the tenth catalyst mayreduce at least a portion of components that contribute to the MCRcontent of the hydrocarbon feed, while maintaining hydrocarbonfeed/total product stability.

In certain embodiments, an eleventh type of catalyst (“eleventhcatalyst”) is obtainable by combining a used catalyst with a support andColumns 6-10 metals to produce an the eleventh catalyst. The eleventhcatalyst may have from 0.001 grams to 0.3 grams, 0.005 grams to 0.2grams, or 0.01 grams to 0.1 grams of Column 6 metal(s) per gram ofeleventh catalyst. In some embodiments, the eleventh catalyst may haveat most 0.1 grams of Column 6 metal(s). In some embodiments, theeleventh catalyst may include from 0.001 grams to 0.1 grams, 0.005 to0.05 grams, or from 0.01 grams to 0.03 grams of Column 10 metal(s) pergram of eleventh catalyst. In certain embodiments, the eleventh catalystmay include from 0.001 grams to 0.1 grams, 0.005 to 0.05 grams, or from0.01 grams to 0.03 grams of Column 9 metal(s) per gram of eleventhcatalyst. The eleventh catalyst has, in some embodiments, a pore sizedistribution with a median pore diameter from 50 Å to 130 Å. Theeleventh catalyst may reduce at least a portion of the components thatcontribute to higher viscosities, a portion of the components thatcontribute to residue and/or basic nitrogen compounds in the hydrocarbonfeed.

In some embodiments, a twelfth type of catalyst (“twelfth catalyst”) maybe obtainable by combining a support with Column 6 metal(s) to produce acatalyst precursor. The catalyst precursor may be heated in the presenceof one or more sulfur containing compounds at a temperature below 300°C. or below 150° C. for a time period of less than 24 hours, less than12 hours, less than 8 hours, or less than 6 hours to form the driedtwelfth catalyst. Typically, the catalyst precursor is heated from 100°C. to 150° C. for 8 hours. In certain embodiments, the twelfth catalystmay, per gram of catalyst, have a Column 15 element content in a rangefrom 0.001 grams to 0.03 grams, 0.005 grams to 0.02 grams, or 0.008grams to 0.01 grams. The twelfth catalyst may exhibit significantactivity and stability when used to treat the hydrocarbon feed asdescribed herein. In some embodiments, the dried catalyst may besulfided in situ with a hydrocarbon feed having sufficient sulfurcontent to convert a portion of the metal oxides to metal sulfides. Thetwelfth catalyst may reduce at least a portion of the components thatcontribute to higher viscosities, a portion of the components thatcontribute to residue, basic nitrogen compounds, C₅ asphaltenes and C₇asphaltenes in the hydrocarbon feed.

A thirteenth type of catalyst (“thirteenth” catalyst may be prepared bycombining Columns 6-10 metal(s) with mineral oxides having a particlesize of at most 500 micrometer, and a support. The thirteenth catalystmay have from 0.001 grams to 0.3 grams, 0.005 grams to 0.2 grams, or0.01 grams to 0.1 grams of Column 6 metal(s), per gram of thirteenthcatalyst. In some embodiments, the thirteenth catalyst may have at most0.1 grams of Column 6 metal(s). In certain embodiments, the thirteenthcatalyst has at most 0.06 grams of Column 6 metal(s) per gram ofthirteenth catalyst. In some embodiments, the thirteenth catalyst mayinclude from 0.001 grams to 0.1 grams, 0.005 grams to 0.05 grams, orfrom 0.01 grams to 0.03 grams of Column 10 metal(s) per gram ofcatalyst. In certain embodiments, the thirteenth catalyst may includefrom 0.001 grams to 0.1 grams, 0.005 to 0.05 grams, or from 0.01 gramsto 0.03 grams of Column 9 metal(s) and/or Columns 10 metal(s) per gramof thirteenth catalyst. The thirteenth catalyst may include, per gram ofthirteenth catalyst, from 0.01 grams to 0.8 grams, 0.02 grams to 0.7grams, or 0.03 grams to 0.6 grams of mineral oxides. The thirteenthcatalyst has, in some embodiments, a pore size distribution with amedian pore diameter from 50 Å to 130 Å. The thirteenth catalyst mayhave less than 1% of pores having a pore size of at most 70 Å; from 20%to 30% of pores having a pore size between 70-100 Å; from 30% to 40% ofpores having a pore size between 100-130 Å; from 1% to 10% of poreshaving a pore size between 130-150 Å; from 0.1% to 5% of pores having apore size between 150-180 Å; from 0.1% to 5% of pores having a pore sizebetween 150-180 Å; from 0.1 to 5% of pores having a pore size between180-200 Å; from 0.001% to 1% of pores having a pore size between200-1000 Å; from 1% to 10% of pores having a pore size between 1000-5000Å; from 20% to 25% of pores having a pore size of at least 5000 Å Thethirteenth catalyst may reduce at least a portion of the components thatcontribute to higher viscosities, a portion of the components thatcontribute to residue, C₅ asphaltenes, and/or basic nitrogen compoundsin the hydrocarbon feed.

Other embodiments of the first through thirteenth catalysts may also bemade and/or used as is otherwise described herein.

Selecting the catalyst(s) of this application and controlling operatingconditions may allow a crude product to be produced that has TAN and/orselected properties changed relative to the hydrocarbon feed while otherproperties of the hydrocarbon feed are not significantly changed. Theresulting crude product may have enhanced properties relative to thehydrocarbon feed and, thus, be more acceptable for transportation and/orrefining.

Arrangement of two or more catalysts in a selected sequence may controlthe sequence of property improvements for the hydrocarbon feed. Forexample, TAN, API gravity, at least a portion of the C₅ asphaltenes, atleast a portion of the iron, at least a portion of the nickel, and/or atleast a portion of the vanadium in the hydrocarbon feed can be reducedbefore at least a portion of heteroatoms in the hydrocarbon feed arereduced.

Arrangement and/or selection of the catalysts may, in some embodiments,improve lives of the catalysts and/or the stability of the hydrocarbonfeed/total product mixture. Improvement of a catalyst life and/orstability of the hydrocarbon feed/total product mixture duringprocessing may allow a contacting system to operate for at least 3months, at least 6 months, or at least 1 year without replacement of thecatalyst in the contacting zone.

Combinations of selected catalysts may allow reduction in at least aportion of the Ni/V/Fe, at least a portion of the C₅ asphaltenes, atleast a portion of the metals in metal salts of organic acids, at leasta portion of the components that contribute to TAN, at least a portionof the residue, or combinations thereof, from the hydrocarbon feedbefore other properties of the hydrocarbon feed are changed, whilemaintaining the stability of the hydrocarbon feed/total product mixtureduring processing (for example, maintaining a hydrocarbon feed P-valueof above 1.5). Alternatively, C₅ asphaltenes, TAN, and/or API gravitymay be incrementally reduced by contact of the hydrocarbon feed withselected catalysts. The ability to incrementally and/or selectivelychange properties of the hydrocarbon feed may allow the stability of thehydrocarbon feed/total product mixture to be maintained duringprocessing.

In some embodiments, the first catalyst (described above) may bepositioned upstream of a series of catalysts. Such positioning of thefirst catalyst may allow removal of high molecular weight contaminants,metal contaminants, and/or metals in metal salts of organic acids, whilemaintaining the stability of the hydrocarbon feed/total product mixture.

The first catalyst allows, in some embodiments, for removal of at leasta portion of Ni/V/Fe, removal of acidic components, removal ofcomponents that contribute to a decrease in the life of other catalystsin the system, or combinations thereof, from the hydrocarbon feed. Forexample, reducing at least a portion of C₅ asphaltenes in thehydrocarbon feed/total product mixture relative to the hydrocarbon feedinhibits plugging of other catalysts positioned downstream, and thus,increases the length of time the contacting system may be operatedwithout replenishment of catalyst. Removal of at least a portion of theNi/V/Fe from the hydrocarbon feed may, in some embodiments, increase alife of one or more catalysts positioned after the first catalyst.

The second catalyst(s) and/or the third catalyst(s) may be positioneddownstream of the first catalyst. Further contact of the hydrocarbonfeed/total product mixture with the second catalyst(s) and/or thirdcatalyst(s) may further reduce TAN, reduce the content of Ni/V/Fe,reduce sulfur content, reduce oxygen content, and/or reduce the contentof metals in metal salts of organic acids.

In some embodiments, contact of the hydrocarbon feed with the secondcatalyst(s) and/or the third catalyst(s) may produce a hydrocarbonfeed/total product mixture that has a reduced TAN, a reduced sulfurcontent, a reduced oxygen content, a reduced content of metals in metalsalts of organic acids, a reduced asphaltenes content, a reducedviscosity, or combinations thereof, relative to the respectiveproperties of the hydrocarbon feed while maintaining the stability ofthe hydrocarbon feed/total product mixture during processing. The secondcatalyst may be positioned in series, either with the second catalystbeing upstream of the third catalyst, or vice versa.

The ability to deliver hydrogen to specified contacting zones tends tominimize hydrogen usage during contacting. Combinations of catalyststhat facility generation of hydrogen during contacting, and catalyststhat uptake a relatively low amount of hydrogen during contacting, maybe used to change selected properties of a crude product relative to thesame properties of the hydrocarbon feed. For example, the fourthcatalyst may be used in combination with the first catalyst(s), secondcatalyst(s), third catalyst(s), fifth catalyst(s), sixth catalyst(s),and/or seventh catalyst(s) to change selected properties of ahydrocarbon feed, while only changing other properties of thehydrocarbon feed by selected amounts, and/or while maintaininghydrocarbon feed/total product stability. The order and/or number ofcatalysts may be selected to minimize net hydrogen uptake whilemaintaining the hydrocarbon feed/total product stability. Minimal nethydrogen uptake allows residue content, VGO content, distillate content,API gravity, or combinations thereof of the hydrocarbon feed to bemaintained within 20% of the respective properties of the hydrocarbonfeed, while the TAN and/or the viscosity of the crude product is at most90% of the TAN and/or the viscosity of the hydrocarbon feed.

Reduction in net hydrogen uptake by the hydrocarbon feed may produce acrude product that has a boiling range distribution similar to theboiling point distribution of the hydrocarbon feed, and a reduced TANrelative to the TAN of the hydrocarbon feed. The atomic H/C of the crudeproduct may also only change by relatively small amounts as compared tothe atomic H/C of the hydrocarbon feed.

Hydrogen generation in specific contacting zones may allow selectiveaddition of hydrogen to other contacting zones and/or allow selectivereduction of properties of the hydrocarbon feed. In some embodiments,fourth catalyst(s) may be positioned upstream, downstream, or betweenadditional catalyst(s) described herein. Hydrogen may be generatedduring contacting of the hydrocarbon feed with the fourth catalyst(s),and hydrogen may be delivered to the contacting zones that include theadditional catalyst(s). The delivery of the hydrogen may be counter tothe flow of the hydrocarbon feed. In some embodiments, the delivery ofthe hydrogen may be concurrent to the flow of the hydrocarbon feed.

For example, in a stacked configuration (see, for example, FIG. 2B),hydrogen may be generated during contacting in one contacting zone (forexample, contacting zone 102 in FIG. 2B), and hydrogen may be deliveredto an additional contacting zone (for example, contacting zone 114 inFIG. 2B) in a direction that is counter to flow of the hydrocarbon feed.In some embodiments, the hydrogen flow may be concurrent with the flowof the hydrocarbon feed. Alternatively, in a stacked configuration (see,for example, FIG. 3B), hydrogen may be generated during contacting inone contacting zone (for example, contacting zone 102 in FIG. 3B). Ahydrogen source may be delivered to a first additional contacting zonein a direction that is counter to flow of the hydrocarbon feed (forexample, adding hydrogen through conduit 106′ to contacting zone 114 inFIG. 3B), and to a second additional contacting zone in a direction thatis concurrent to the flow of the hydrocarbon feed (for example, addinghydrogen through conduit 106′ to contacting zone 116 in FIG. 3B).

In some embodiments, the fourth catalyst and the sixth catalyst are usedin series, either with the fourth catalyst being upstream of the sixthcatalyst, or vice versa. The combination of the fourth catalyst with anadditional catalyst(s) may reduce TAN, reduce Ni/V/Fe content, and/orreduce a content of metals in metal salts of organic acids, with low netuptake of hydrogen by the hydrocarbon feed. Low net hydrogen uptake mayallow other properties of the crude product to be only changed by smallamounts relative to the same properties of the hydrocarbon feed.

In some embodiments, two different seventh catalysts may be used incombination. The seventh catalyst used upstream from the downstreamseventh catalyst may have a total content of Column 6 metal(s), per gramof catalyst, in a range from 0.0001-0.06 grams. The downstream seventhcatalyst may have a total content of Column 6 metals(s), per gram ofdownstream seventh catalyst, that is equal to or larger than the totalcontent of Column 6 metal(s) in the upstream seventh catalyst, or atleast 0.02 grams of Column 6 metal(s) per gram of catalyst. In someembodiments, the position of the upstream seventh catalyst and thedownstream seventh catalyst may be reversed. The ability to use arelatively small amount of catalytic active metal in the downstreamseventh catalyst may allow other properties of the crude product to beonly changed by small amounts relative to the same properties of thehydrocarbon feed (for example, a relatively small change in heteroatomcontent, API gravity, residue content, VGO content, or combinationsthereof).

Contact of the hydrocarbon feed with the upstream and downstream seventhcatalysts may produce a crude product that has a TAN of at most 90%, atmost 80%, at most 50%, at most 10%, or at least 1% of the TAN of thehydrocarbon feed. In some embodiments, the TAN of the hydrocarbon feedmay be incrementally reduced by contact with the upstream and downstreamseventh catalysts (for example, contact of the hydrocarbon feed with acatalyst to form an initial crude product with changed propertiesrelative to the hydrocarbon feed, and then contact of the initial crudeproduct with an additional catalyst to produce the crude product withchanged properties relative to the initial crude product). The abilityto reduce TAN incrementally may assist in maintaining the stability ofthe hydrocarbon feed/total product mixture during processing.

In some embodiments, catalyst selection and/or order of catalysts incombination with controlled contacting conditions (for example,temperature and/or hydrocarbon feed flow rate) may assist in reducinghydrogen uptake by the hydrocarbon feed, maintaining hydrocarbonfeed/total product mixture stability during processing, and changing oneor more properties of the crude product relative to the respectiveproperties of the hydrocarbon feed. Stability of the hydrocarbonfeed/total product mixture may be affected by various phases separatingfrom the hydrocarbon feed/total product mixture. Phase separation may becaused by, for example, insolubility of the hydrocarbon feed and/orcrude product in the hydrocarbon feed/total product mixture,flocculation of asphaltenes from the hydrocarbon feed/total productmixture, precipitation of components from the hydrocarbon feed/totalproduct mixture, or combinations thereof.

At certain times during the contacting period, the concentration ofhydrocarbon feed and/or total product in the hydrocarbon feed/totalproduct mixture may change. As the concentration of the total product inthe hydrocarbon feed/total product mixture changes due to formation ofthe crude product, solubility of the components of the hydrocarbon feedand/or components of the total product in the hydrocarbon feed/totalproduct mixture tends to change. For example, the hydrocarbon feed maycontain components that are soluble in the hydrocarbon feed at thebeginning of processing. As properties of the hydrocarbon feed change(for example, TAN, MCR, C₅ asphaltenes, P-value, or combinationsthereof), the components may tend to become less soluble in thehydrocarbon feed/total product mixture. In some instances, thehydrocarbon feed and the total product may form two phases and/or becomeinsoluble in one another. Solubility changes may also result in thehydrocarbon feed/total product mixture forming two or more phases.Formation of two phases, through flocculation of asphaltenes, change inconcentration of hydrocarbon feed and total product, and/orprecipitation of components, tends to reduce the life of one or more ofthe catalysts. Additionally, the efficiency of the process may bereduced. For example, repeated treatment of the hydrocarbon feed/totalproduct mixture may be necessary to produce a crude product with desiredproperties.

During processing, the P-value of the hydrocarbon feed/total productmixture may be monitored and the stability of the process, hydrocarbonfeed, and/or hydrocarbon feed/total product mixture may be assessed.Typically, a P-value that is at most 1.0 indicates that flocculation ofasphaltenes from the hydrocarbon feed generally occurs. If the P-valueis initially at least 1.0, and such P-value increases or is relativelystable during contacting, then this indicates that the hydrocarbon feedis relatively stabile during contacting. Hydrocarbon feed/total productmixture stability, as assessed by P-value, may be controlled bycontrolling contacting conditions, by selection of catalysts, byselective ordering of catalysts, or combinations thereof. Suchcontrolling of contacting conditions may include controlling LHSV,temperature, pressure, hydrogen uptake, hydrocarbon feed flow, orcombinations thereof.

Typically, hydrocarbon feed having viscosities that inhibit thehydrocarbon feed from being transported and/or pumped are contacted atelevated hydrogen pressures (for example, at least 7 MPa, at least 10MPa or at least 15 MPa) to produce products that are more fluid. Atelevated hydrogen pressures coke formation is inhibited, thus theproperties of the hydrocarbon feed may be changed with minimal cokeproduction. Since reduction of viscosity, residue and C₅/C₇ asphaltenesis not dependent on hydrogen pressure reduction of these properties maynot occur unless the contacting temperature is at least 300° C. For somehydrocarbon feeds, temperatures of at least 350° C. may be required toreduce desired properties of the hydrocarbon feed to produce a productthat meets the desired specifications. At increased temperatures cokeformation may occur, even at elevated hydrogen pressures. As theproperties of the hydrocarbon feed are changed, the P-value of thehydrocarbon feed/total product may decrease below 1.0 and/or sedimentmay form, causing the product mixture to become unstable. Since,elevated hydrogen pressures require large amounts of hydrogen, a processcapable of reducing properties that are independent of pressure atminimal temperatures is desirable.

Contact of a hydrocarbon feed having a viscosity of at least 10 cSt at37.8° C. (for example, at least 100 cSt, at least 1000 cSt, or at least2000 cSt) in a controlled temperature range of 370° C. to 450° C., 390°C. to 440° C., or from 400° C. to 430° C. at pressures of at most 7 MPawith one or more catalysts described herein produces a crude producthaving changed properties (for example, viscosity, residue and C₅/C₇asphaltenes) of at most 50%, at most 30%, at most 20%, at most 10%, atmost 1% of the respective property of the hydrocarbon feed. Duringcontact, the P-value remains may be kept above 1.0 by controlling thecontacting temperature. For example, in some embodiments, if thetemperature increases above 450° C., the P-value drops below 1.0 and thehydrocarbon feed/total product mixture becomes unstable. If thetemperature decreases below 370° C., minimal changes to the hydrocarbonfeed properties occurs.

In some embodiments, contacting temperatures are controlled such that C₅asphaltenes and/or other asphaltenes are removed while maintaining theMCR content of the hydrocarbon feed. Reduction of the MCR contentthrough hydrogen uptake and/or higher contacting temperatures may resultin formation of two phases that may reduce the stability of thehydrocarbon feed/total product mixture and/or life of one or more of thecatalysts. Control of contacting temperature and hydrogen uptake incombination with the catalysts described herein allows the C₅asphaltenes to be reduced while the MCR content of the hydrocarbon feedonly changes by a relatively small amount.

In some embodiments, contacting conditions are controlled such thattemperatures in one or more contacting zones may be different. Operatingat different temperatures allows for selective change in hydrocarbonfeed properties while maintaining the stability of the hydrocarbonfeed/total product mixture. The hydrocarbon feed enters a firstcontacting zone at the start of a process. A first contactingtemperature is the temperature in the first contacting zone. Othercontacting temperatures (for example, second temperature, thirdtemperature, fourth temperature, et cetera) are the temperatures incontacting zones that are positioned after the first contacting zone. Afirst contacting temperature may be in a range from 100-420° C. and asecond contacting temperature may be in a range that is 20-100° C.,30-90° C., or 40-60° C. different than the first contacting temperature.In some embodiments, the second contacting temperature is greater thanthe first contacting temperature. Having different contactingtemperatures may reduce TAN and/or C₅ asphaltenes content in a crudeproduct relative to the TAN and/or the C₅ asphaltenes content of thehydrocarbon feed to a greater extent than the amount of TAN and/or C₅asphaltene reduction, if any, when the first and second contactingtemperatures are the same as or within 10° C. of each other.

For example, a first contacting zone may include a first catalyst(s)and/or a fourth catalyst(s) and a second contacting zone may includeother catalyst(s) described herein. The first contacting temperature maybe 350° C. and the second contacting temperature may be 300° C. Contactof the hydrocarbon feed in the first contacting zone with the firstcatalyst and/or fourth catalyst at the higher temperature prior tocontact with the other catalyst(s) in the second contacting zone mayresult in greater TAN and/or C₅ asphaltenes reduction in the hydrocarbonfeed relative to the TAN and/or C₅ asphaltenes reduction in the samehydrocarbon feed when the first and second contacting temperatures arewithin 10° C.

In some embodiments, contacting conditions are controlled such that thetotal hydrogen partial pressure of the contacting zone is maintained ata desired pressure, at a set flow rate and elevated temperatures. Theability to operate at partial pressures of hydrogen of at most 3.5 MPaallows an increase in LHSV (for example an increase to at least 0.5 h⁻¹,at least 1 h⁻¹, at least 2 h⁻¹, at least 5 h⁻¹, or at least 10 h⁻¹) withthe same or longer catalyst life as contacting at hydrogen partialpressures of at least 4 MPa. Operating at lower partial pressures ofhydrogen decreases the cost of the operation and allows contacting to beperformed where limited amounts of hydrogen are available.

For example, a contacting zone may include a fourth catalyst and/or afifth catalyst. The contacting conditions may be: temperature of above360° C., a LHSV of 1 h⁻¹, a total hydrogen partial pressure of 3.5 MPa.Contact of the hydrocarbon feed with the fourth and/or fifth catalyst atthese conditions may allow continuous use of a catalyst for at least 500hours, while reducing desired properties of the hydrocarbon feed.

In some embodiments, removal of at least a portion of the organometalliccompounds and/or metals from the hydrocarbon feed is performed beforethe hydrocarbon feed is contacted with other catalysts. For example, asmall amount of organomolybdenum (for example, at most 50 wtppm, at most20 wtppm, or at most 10 wtppm) in a hydrocarbon feed may reduce theactivity of a catalyst upon contact of the hydrocarbon feed with thecatalyst. Organomolybdenum may form molybdenum sulfides duringcontacting with the catalyst. The molybdenum sulfides may precipitatefrom solution causing solid molybdenum compounds to accumulate in thereactor. The accumulation of precipitates in the reactor may lead to apressure drop in the contacting zone, thus inhibiting hydrocarbon feedfrom passing through the contacting zone at desired flow rates.Organometallic compounds may also promote formation of coke duringcontacting. Removal of at least a portion of the “active” organometalliccompounds and/or metals from the hydrocarbon feed may increase the livesof catalysts used in a hydroprocessing process and/or increaseefficiency of the treatment process. Removal of the activeorganometallic compounds may further allow the hydrocarbon feed to beprocessed in a more efficient manner. For example, a first contactingzone may include an eighth catalyst and a second contacting zone mayinclude a ninth catalyst. Contact of a hydrocarbon feed having at least0.1 wtppm of molybdenum at contacting temperatures of at most 7 MPa, aLHSV of at least 0.1 h⁻¹, and a temperature of at least 300° C. with theeight catalyst may result in reduction of at least a portion of theorganomolybdenum in the hydrocarbon feed. Contact of the reducedmolybdenum hydrocarbon feed with the ninth catalyst may result in atleast a portion of the Ni/V/Fe and at least a portion of the componentscontributing residue, C₅/C₇ asphaltenes, and/or viscosity to be reducedto produce a crude product suitable for transportation and/or furtherprocessing.

In some embodiments, a sixth catalyst and/or tenth catalyst may bepositioned in a third contacting zone downstream of the first contactingzone and upstream of the second contacting zone. Contact of the reducedmolybdenum hydrocarbon feed with the catalyst in the third contactingzone may reduce additional amounts of Ni/V/Fe without an increasing theoperating pressure above 7 MPa.

Hydrocarbon feeds having an API gravity of at most 10 (for example,bitumen and/or heavy oil/tar sands crude) may be converted into varioushydrocarbons streams through a series of processing steps. For example,crude may be mined from a hydrocarbon formation and bitumen may beextracted from the crude. During the extraction process, the bitumen isdiluted with naphtha. Before the bitumen is treated, the diluent naphthais removed and the resulting product is vacuum distilled unit to producelight hydrocarbons and heavy hydrocarbons. The light hydrocarbons aretransported for further processing. The heavier bitumen components aretypically processed in one or more cokers and one or more residuehydrocracking units (for example, ebullating bed units such as anLC-Finer). Coking (for example, fluid coking and/or delayed cokingprocesses) involves the thermal cracking of bitumen molecules intolighter components.

In the residue hydrocracking unit, heavier bitumen components arecontacted with a catalyst in the presence of hydrocarbons to producelighter components and an unconverted residual stream. The unconvertedresidual stream may be sent to the fluid cokers to supplement the feedto those units. The residue hydrocracking unit may process 50,000barrels per day of a 60/40 mix of bitumen and vacuum topped bitumenfeed.

Reduction of the viscosity and/or residue content of a hydrocarbon feedto produce a feed stream that may be processed in a residuehydrocracking unit may enhance the processing rate of hydrocarbon feed.A system using the methods and catalysts described herein to changeproperties of a hydrocarbon feed may be positioned upstream of one ormore cracking units (for example, an ebullating bed cracking unit, afluid catalytic cracking unit, thermal cracking unit, or other unitsknown to convert hydrocarbon feed to lighter components). Treatment ofthe hydrocarbon feed in one or more systems described herein may producea feed that improves the processing rate of the cracking unit by atleast a factor of 2, at least a factor of 4, at least a factor of 10, orat least a factor of 100. For example, a system for treating ahydrocarbon feed having a viscosity of at least 100 cSt at 37.8° C.and/or 0.1 grams of residue per gram of hydrocarbon feed may include oneor more contacting systems described herein positioned upstream of acracking unit. The contacting system may include one or more catalystsdescribed herein capable of producing a crude product having a viscosityof at most 50% of the viscosity of the hydrocarbon feed at 37.8° C.and/or at most 90% of the residue of the hydrocarbon feed. The crudeproduct and/or a mixture of the crude product and hydrocarbon feed mayenter a residue hydrocracking unit. Since the crude product and/ormixture of the crude product and hydrocarbon feed has a lower viscositythan the original hydrocarbon feed, the processing rate through thecracking unit may be improved.

Hydrocarbon feeds having at least 0.01 grams of C₅ asphaltenes may bedeasphalted prior to hydroprocessing treatment in a refinery operation.Deasphalting processes may involve solvent extraction and/or contactingthe crude with a catalyst to remove asphaltenes. Reduction of at least aportion of the components that contribute to viscosity, at least aportion of the components that contribute to residue and/or asphaltenesprior to the deasphalting process may eliminate the need for solventextraction, reduce the amount of required solvent, and/or enhance theefficiency of the deasphalting process. For example, a system fortreating a hydrocarbon feed having, per gram of hydrocarbon feed, atleast 0.01 grams of C₅ asphaltenes and/or 0.1 grams of residue and aviscosity of at least 10 cSt at 37.8° C. may include one or morecontacting systems described herein positioned upstream of andeasphalting unit. The contacting system may include one or morecatalysts described herein capable of producing a crude product having aC₅ asphaltenes content of at most 50% of the hydrocarbon feed C₅asphaltenes content, a residue content of at most 90% of the hydrocarbonfeed residue content, a viscosity of at most 50% of the hydrocarbonviscosity or combinations thereof. The crude product and/or a mixture ofthe crude product and hydrocarbon feed may enter the deasphalting unit.Since the crude product and/or mixture of the crude product and thehydrocarbon feed has a lower asphaltene, residue and/or viscosity thanthe original hydrocarbon feed, the processing efficiency of thedeasphalting unit may be increased by at least 5%, at least 10%, atleast 20% or at least 50% of the original efficiency.

In some embodiments, contact of a crude feed with one or more catalystsdescribed herein produces a crude product that has enhancedconcentrations of naphtha. The naphtha may be separated from the crudeproduct and mixed with crude feed to produce a feed that is suitable fortransportation and/or meets pipeline specification. For example, a crudefeed may be contacted with at least a third catalyst and a zeolitecatalyst. The zeolite catalyst may be a 10 wt %, 20 wt %, 30 wt %, or 40wt % USY zeolite catalyst, and/or an ultra stable Y zeolite catalyst.The zeolite catalyst may reduce a portion of the hydrocarbons to producenaphtha. The naphtha may be separated from the crude product using knownfractional distillation methods and mixed with the crude feed, adifferent crude feed, and/or other hydrocarbons to form a blend.

EXAMPLES

Non-limiting examples of support preparation, catalyst preparations, andsystems with selected arrangement of catalysts and controlled contactingconditions are set forth below.

Example 1 Preparation of a Catalyst Support

A support was prepared by mulling 576 grams of alumina (CriterionCatalysts and Technologies LP, Michigan City, Mich., U.S.A.) with 585grams of water and 8 grams of glacial nitric acid for 35 minutes. Theresulting mulled mixture was extruded through a 1.3 Trilobe™ die plate,dried between 90 and 125° C., and then calcined at 918° C., whichresulted in 650 grams of a calcined support with a median pore diameterof 182 Å. The calcined support was placed in a Lindberg furnace. Thefurnace temperature was raised to 1000-1100° C. over 1.5 hours, and thenheld in this range for 2 hours to produce the support. The supportincluded, per gram of support, 0.0003 grams of gamma alumina, 0.0008grams of alpha alumina, 0.0208 grams of delta alumina, and 0.9781 gramsof theta alumina, as determined by x-ray diffraction. The support had asurface area of 110 m²/g and a total pore volume of 0.821 cm³/g. Thesupport had a pore size distribution with a median pore diameter of 232Å, with 66.7% of the total number of pores in the pore size distributionhaving a pore diameter within 85 Å of the median pore diameter.

This example demonstrates how to prepare a support that has a pore sizedistribution of at least 180 Å and includes at least 0.1 grams of thetaalumina.

Example 2 Preparation of a Vanadium Catalyst Having a Pore SizeDistribution with a Median Pore Diameter of at Least 230 Å

The vanadium catalyst was prepared in the following manner. The aluminasupport, prepared by the method described in Example 1, was impregnatedwith a vanadium impregnation solution prepared by combining 7.69 gramsof VOSO₄ with 82 grams of deionized water. A pH of the solution was2.27.

The alumina support (100 g) was impregnated with the vanadiumimpregnation solution, aged for 2 hours with occasional agitation, driedat 125° C. for several hours, and then calcined at 480° C. for 2 hours.The resulting catalyst contained 0.04 grams of vanadium, per gram ofcatalyst, with the balance being support. The vanadium catalyst had apore size distribution with a median pore diameter of 350 Å, a porevolume of 0.69 cm³/g, and a surface area of 110 m²/g. Additionally,66.7% of the total number of pores in the pore size distribution of thevanadium catalyst had a pore diameter within 70 Å of the median porediameter.

This example demonstrates the preparation of a Column 5 catalyst havinga pore size distribution with a median pore diameter of at least 230 Å.

Example 3 Preparation of a Molybdenum Catalyst Having a Pore SizeDistribution with a Median Pore Diameter of at Least 230 Å

The molybdenum catalyst was prepared in the following manner. Thealumina support prepared by the method described in Example 1 wasimpregnated with a molybdenum impregnation solution. The molybdenumimpregnation solution was prepared by combining 4.26 grams of(NH₄)₂Mo₂O₇, 6.38 grams of MoO₃, 1.12 grams of 30% H₂O₂, 0.27 grams ofmonoethanolamine (MEA), and 6.51 grams of deionized water to form aslurry. The slurry was heated to 65° C. until dissolution of the solids.The heated solution was cooled to room temperature. The pH of thesolution was 5.36. The solution volume was adjusted to 82 mL withdeionized water.

The alumina support (100 grams) was impregnated with the molybdenumimpregnation solution, aged for 2 hours with occasional agitation, driedat 125° C. for several hours, and then calcined at 480° C. for 2 hours.The resulting catalyst contained 0.04 grams of molybdenum per gram ofcatalyst, with the balance being support. The molybdenum catalyst had apore size distribution with a median pore diameter of 250 Å, a porevolume of 0.77 cm³/g, and a surface area of 116 m²/g. Additionally,67.7% of the total number of pores in the pore size distribution of themolybdenum catalyst had a pore diameter within 86 Å of the median porediameter.

The molybdenum catalyst exhibited bands near 810 cm⁻¹, 834 cm⁻¹, and 880cm⁻¹ when analyzed by Raman Spectroscopy. The Raman spectrum of thecatalyst was obtained on a Chromex Raman 200 spectrometer operated atfour-wavenumber resolution. The excitation wavelength was 785 nm at apower of approximately 45 mW at the sample. The spectrometer wavenumberscale was calibrated using the known bands of 4-acetominophenol. Theband positions of 4-actiominophenol were reproduced to within ±cm⁻¹. Amolybdenum catalyst with a gamma alumina support did not exhibit bandsbetween 810 cm⁻¹ and 900 cm⁻¹ when analyzed by Raman Spectroscopy. FIG.7 depicts the spectrum of the two catalysts. Plot 138 represents themolybdenum catalyst having a pore size distribution with a median porediameter of 250 Å. Plot 140 represents a Column 6/Column 10 metalcatalyst that includes at least 0.5 grams of gamma alumina having a poresize distribution with a median pore diameter of 120 Å.

This example demonstrates the preparation of a Column 6 metal catalysthaving a pore size distribution with a median pore diameter of at least230 Å. This example also demonstrates preparation of a Column 6 metalcatalyst having bands near 810 cm⁻¹, 834 cm⁻¹, and 880 cm⁻¹, asdetermined by Raman Spectroscopy. The catalyst prepared by this methodis different than a gamma alumina catalyst having a pore sizedistribution with a median pore diameter of at least 100 Å.

Example 4 Preparation of a Molybdenum/Vanadium Catalyst Having a PoreSize Distribution with a Median Pore Diameter of at Least 230 Å

The molybdenum/vanadium catalyst was prepared in the following manner.The alumina support, prepared by the method described in Example 1, wasimpregnated with a molybdenum/vanadium impregnation solution prepared asfollows. A first solution was made by combining 2.14 grams of(NH₄)₂Mo₂O₇, 3.21 grams of MoO₃, 0.56 grams of 30% hydrogen peroxide(H₂O₂), 0.14 grams of monoethanolamine (MEA), and 3.28 grams ofdeionized water to form a slurry. The slurry was heated to 65° C. untildissolution of the solids. The heated solution was cooled to roomtemperature.

A second solution was made by combining 3.57 grams of VOSO₄ with 40grams of deionized water. The first solution and second solution werecombined and sufficient deionized water was added to bring the combinedsolution volume up to 82 ml to yield the molybdenum/vanadiumimpregnation solution. The alumina was impregnated with themolybdenum/vanadium impregnation solution, aged for 2 hours withoccasional agitation, dried at 125° C. for several hours, and thencalcined at 480° C. for 2 hours. The resulting catalyst contained, pergram of catalyst, 0.02 grams of vanadium and 0.02 grams of molybdenum,with the balance being support. The molybdenum/vanadium catalyst had apore size distribution with a median pore diameter of 300 Å.

This example demonstrates the preparation of a Column 6 metal and aColumn 5 metal catalyst having a pore size distribution with a medianpore diameter of at least 230 Å. The vanadium/molybdenum catalystexhibited bands near 770 cm⁻¹ and 990 cm⁻¹ when analyzed by RamanSpectroscopy. FIG. 7 depicts the spectrum of the vanadium catalyst. Plot142 represents the molybdenum catalyst having a pore size distributionwith a median pore diameter of 250 Å.

This example also demonstrates the preparation of a Column 5 catalysthaving bands near 770 cm⁻¹ and 990 cm⁻¹ when analyzed by RamanSpectroscopy.

Example 5 Contact of a Crude Feed with Three Catalysts

A tubular reactor with a centrally positioned thermowell was equippedwith thermocouples to measure temperatures throughout a catalyst bed.The catalyst bed was formed by filling the space between the thermowelland an inner wall of the reactor with catalysts and silicon carbide(20-grid, Stanford Materials; Aliso Viejo, Calif.). Such silicon carbideis believed to have low, if any, catalytic properties under the processconditions described herein. All catalysts were blended with an equalvolume amount of silicon carbide before placing the mixture into thecontacting zone portions of the reactor.

The crude feed flow to the reactor was from the top of the reactor tothe bottom of the reactor. Silicon carbide was positioned at the bottomof the reactor to serve as a bottom support. A bottom catalyst/siliconcarbide mixture (42 cm³) was positioned on top of the silicon carbide toform a bottom contacting zone. The bottom catalyst had a pore sizedistribution with a median pore diameter of 77 Å, with 66.7% of thetotal number of pores in the pore size distribution having a porediameter within 20 Å of the median pore diameter. The bottom catalystcontained 0.095 grams of molybdenum and 0.025 grams of nickel per gramof catalyst, with the balance being an alumina support.

A middle catalyst/silicone carbide mixture (56 cm³) was positioned ontop of the bottom contacting zone to form a middle contacting zone. Themiddle catalyst had a pore size distribution with a median pore diameterof 98 Å, with 66.7% of the total number of pores in the pore sizedistribution having a pore diameter within 24 Å of the median porediameter. The middle catalyst contained 0.02 grams of nickel and 0.08grams of molybdenum per gram of catalyst, with the balance being analumina support.

A top catalyst/silicone carbide mixture (42 cm³) was positioned on topof the middle contacting zone to form a top contacting zone. The topcatalyst had a pore size distribution with a median pore diameter of 192Å and contained 0.04 grams of molybdenum per gram of catalyst, with thebalance being primarily a gamma alumina support.

Silicon carbide was positioned on top of the top contacting zone to filldead space and to serve as a preheat zone. The catalyst bed was loadedinto a Lindberg furnace that included five heating zones correspondingto the preheat zone, the top, middle, and bottom contacting zones, andthe bottom support.

The catalysts were sulfided by introducing a gaseous mixture of 5 vol %hydrogen sulfide and 95 vol % hydrogen gas into the contacting zones ata rate of 1.5 liter of gaseous mixture per volume (mL) of total catalyst(silicon carbide was not counted as part of the volume of catalyst).Temperatures of the contacting zones were increased to 204° C. (400° F.)over 1 hour and held at 204° C. for 2 hours. After holding at 204° C.,the contacting zones were increased incrementally to 316° C. (600° F.)at a rate of 10° C. (50° F.) per hour. The contacting zones weremaintained at 316° C. for an hour, then incrementally raised to 370° C.(700° F.) over 1 hour and held at 370° C. for two hours. The contactingzones were allowed to cool to ambient temperature.

Crude from the Mars platform in the Gulf of Mexico was filtered, thenheated in an oven at a temperature of 93° C. (200° F.) for 12-24 hoursto form the crude feed having the properties summarized in Table 1, FIG.8. The crude feed was fed to the top of the reactor. The crude feedflowed through the preheat zone, top contacting zone, middle contactingzone, bottom contacting zone, and bottom support of the reactor. Thecrude feed was contacted with each of the catalysts in the presence ofhydrogen gas. Contacting conditions were as follows: ratio of hydrogengas to the crude feed provided to the reactor was 328 Nm³/m³ (2000SCFB), LHSV was 1 h⁻¹, and pressure was 6.9 MPa (1014.7 psi). The threecontacting zones were heated to 370° C. (700° F.) and maintained at 370°C. for 500 hours. Temperatures of the three contacting zones were thenincreased and maintained in the following sequence: 379° C. (715° F.)for 500 hours, and then 388° C. (730° F.) for 500 hours, then 390° C.(734° F.) for 1800 hours, and then 394° C. (742° F.) for 2400 hours.

The total product (that is, the crude product and gas) exited thecatalyst bed. The total product was introduced into a gas-liquid phaseseparator. In the gas-liquid separator, the total product was separatedinto the crude product and gas. Gas input to the system was measured bya mass flow controller. Gas exiting the system was measured by a wettest meter. The crude product was periodically analyzed to determine aweight percentage of components of the crude product. The results listedare averages of the determined weight percentages of components. Crudeproduct properties are summarized in Table 1 of FIG. 8.

As shown in Table 1, the crude product had, per gram of crude product, asulfur content of 0.0075 grams, a residue content of 0.255 grams, anoxygen content of 0.0007 grams. The crude product had a ratio of MCRcontent to C₅ asphaltenes content of 1.9 and a TAN of 0.09. The total ofnickel and vanadium was 22.4 wtppm.

The lives of the catalysts were determined by measuring a weightedaverage bed temperature (“WABT”) versus run length of the crude feed.The catalysts lives may be correlated to the temperature of the catalystbed. It is believed that as catalyst life decreases, a WABT increases.FIG. 9 is a graphical representation of WABT versus time for improvementof the crude feed in the contacting zones described in this example.Plot 144 represents the average WABT of the three contacting zonesversus hours of run time for contacting a crude feed with the top,middle, and bottom catalysts. Over a majority of the run time, the WABTof the contacting zones only changed approximately 20° C. From therelatively stable WABT, it was possible to estimate that the catalyticactivity of the catalyst had not been affected. Typically, a pilot unitrun time of 3000-3500 hours correlates to 1 year of commercialoperation.

This example demonstrates that contacting the crude feed with onecatalyst having a pore size distribution with a median pore diameter ofat least 180 Å and additional catalysts having a pore size distributionwith a median pore diameter in a range between 90-180 Å, with at least60% of the total number of pores in the pore size distribution having apore diameter within 45 Å of the median pore diameter, with controlledcontacting conditions, produced a total product that included the crudeproduct. As measured by P-value, crude feed/total product mixturestability was maintained. The crude product had reduced TAN, reducedNi/V/Fe content, reduced sulfur content, and reduced oxygen contentrelative to the crude feed, while the residue content and the VGOcontent of the crude product was 90%-110% of those properties of thecrude feed.

Example 6 Contact of a Crude Feed with Two Catalysts that have a PoreSize Distribution with a Median Pore Diameter in a Range Between 90-180Å

The reactor apparatus (except for the number and content of contactingzones), catalyst sulfiding method, method of separating the totalproduct and method of analyzing the crude product were the same asdescribed in Example 5. Each catalyst was mixed with an equal volume ofsilicon carbide.

The crude feed flow to the reactor was from the top of the reactor tothe bottom of the reactor. The reactor was filled from bottom to top inthe following manner. Silicon carbide was positioned at the bottom ofthe reactor to serve as a bottom support. A bottom catalyst/siliconcarbide mixture (80 cm³) was positioned on top of the silicon carbide toform a bottom contacting zone. The bottom catalyst had a pore sizedistribution with a median pore diameter of 127 Å, with 66.7% of thetotal number pores in the pore size distribution having a pore diameterwithin 32 Å of the median pore diameter. The bottom catalyst included0.11 grams of molybdenum and 0.02 grams of nickel per gram of catalyst,with the balance being support.

A top catalyst/silicone carbide mixture (80 cm³) was positioned on topof the bottom contacting zone to form the top contacting zone. The topcatalyst had a pore size distribution with a median pore diameter of 100Å, with 66.7% of the total number of pores in the pore size distributionhaving a pore diameter within 20 Å of the median pore diameter. The topcatalyst included 0.03 grams of nickel and 0.12 grams of molybdenum pergram of catalyst, with the balance being alumina. Silicon carbide waspositioned on top of the first contacting zone to fill dead space and toserve as a preheat zone. The catalyst bed was loaded into a Lindbergfurnace that included four heating zones corresponding to the preheatzone, the two contacting zones, and the bottom support.

BS-4 crude (Venezuela) having the properties summarized in Table 2, FIG.10, was fed to the top of the reactor. The crude feed flowed through thepreheat zone, top contacting zone, bottom contacting zone, and bottomsupport of the reactor. The crude feed was contacted with each of thecatalysts in the presence of hydrogen gas. The contacting conditionswere as follows: ratio of hydrogen gas to the crude feed provided to thereactor was 160 Nm³/m³ (1000 SCFB), LHSV was 1 h⁻¹, and pressure was 6.9MPa (1014.7 psi). The two contacting zones were heated to 260° C. (500°F.) and maintained at 260° C. (500° F.) for 287 hours. Temperatures ofthe two contacting zones were then increased and maintained in thefollowing sequence: 270° C. (525° F.) for 190 hours, then 288° C. (550°F.) for 216 hours, then 315° C. (600° F.) for 360 hours, and then 343°C. (650° F.) for 120 hours for a total run time of 1173 hours.

The total product exited the reactor and was separated as described inExample 5. The crude product had an average TAN of 0.42 and an averageAPI gravity of 12.5 during processing. The crude product had, per gramof crude product, 0.0023 grams of sulfur, 0.0034 grams of oxygen, 0.441grams of VGO, and 0.378 grams of residue. Additional properties of thecrude product are listed in TABLE 2 in FIG. 10.

This example demonstrates that contacting the crude feed with thecatalysts having pore size distributions with a median pore diameter ina range between 90-180 Å produced a crude product that had a reducedTAN, a reduced Ni/V/Fe content, and a reduced oxygen content, relativeto the properties of the crude feed, while residue content and VGOcontent of the crude product were 99% and 100% of the respectiveproperties of the crude feed.

Example 7 Contact of a Crude Feed with Two Catalysts

The reactor apparatus (except for number and content of contactingzones), catalysts, the total product separation method, crude productanalysis, and catalyst sulfiding method were the same as described inExample 6.

A crude feed (BC-10 crude) having the properties summarized in Table 3,FIG. 11, was fed to the top of the reactor. The crude feed flowedthrough the preheat zone, top contacting zone, bottom contacting zone,and bottom support of the reactor. The contacting conditions were asfollows: ratio of hydrogen gas to the crude feed provided to the reactorwas 80 Nm³/m³ (500 SCFB), LHSV was 2 h⁻¹, and pressure was 6.9 MPa(1014.7 psi). The two contacting zones were heated incrementally to 343°C. (650° F.). A total run time was 1007 hours.

The crude product had an average TAN of 0.16 and an average API gravityof 16.2 during processing. The crude product had 1.9 wtppm of calcium, 6wtppm of sodium, 0.6 wtppm of zinc, and 3 wtppm of potassium. The crudeproduct had, per gram of crude product, 0.0033 grams of sulfur, 0.002grams of oxygen, 0.376 grams of VGO, and 0.401 grams of residue.Additional properties of the crude product are listed in Table 3 in FIG.11.

This example demonstrates that contacting of the crude feed with theselected catalysts with pore size distributions in a range of 90-180 Åproduced a crude product that had a reduced TAN, a reduced totalcalcium, sodium, zinc, and potassium content while sulfur content, VGOcontent, and residue content of the crude product were 76%, 94%, and103% of the respective properties of the crude feed.

Examples 8-11 Contact of a Crude Feed with Four Catalyst Systems and atVarious Contacting Conditions

Each reactor apparatus (except for the number and content of contactingzones), each total product separation method, and each crude productanalysis were the same as described in Example 5. The catalysts weresulfided using the method as described in U.S. Pat. No. 6,290,841 toGabrielov et al. All catalysts were mixed with silicon carbide in avolume ratio of 2 parts silicon carbide to 1 part catalyst unlessotherwise indicated. The crude feed flow through each reactor was fromthe top of the reactor to the bottom of the reactor. Silicon carbide waspositioned at the bottom of each reactor to serve as a bottom support.Each reactor had a bottom contacting zone and a top contacting zone.After the catalyst/silicone carbide mixtures were placed in thecontacting zones of each reactor, silicone carbide was positioned on topof the top contacting zone to fill dead space and to serve as a preheatzone in each reactor. Each reactor was loaded into a Lindberg furnacethat included four heating zones corresponding to the preheat zone, thetwo contacting zones, and the bottom support.

In Example 8, an uncalcined molybdenum/nickel catalyst/silicon carbidemixture (48 cm³) was positioned in the bottom contacting zone. Thecatalyst included, per gram of catalyst, 0.146 grams of molybdenum,0.047 grams of nickel, and 0.021 grams of phosphorus, with the balancebeing alumina support.

A molybdenum catalyst/silicon carbide mixture (12 cm³) with the catalysthaving a pore size distribution with a median pore diameter of 180 Å waspositioned in the top contacting zone. The molybdenum catalyst had atotal content of 0.04 grams of molybdenum per gram of catalyst, with thebalance being support that included at least 0.50 grams of gamma aluminaper gram of support.

In Example 9, an uncalcined molybdenum/cobalt catalyst/silicon carbidemixture (48 cm³) was positioned in the both contacting zones. Theuncalcined molybdenum/cobalt catalyst included 0.143 grams ofmolybdenum, 0.043 grams of cobalt, and 0.021 grams of phosphorus withthe balance being alumina support.

A molybdenum catalyst/silicon carbide mixture (12 cm³) was positioned inthe top contacting zone. The molybdenum catalyst was the same as in thetop contacting zone of Example 8.

In Example 10, the molybdenum catalyst as described in the topcontacting zone of Example 8 was mixed with silicon carbide andpositioned in the both contacting zones (60 cm³).

In Example 11, an uncalcined molybdenum/nickel catalyst/silicone carbidemixture (48 cm³) was positioned in the bottom contacting zone. Theuncalcined molybdenum/nickel catalyst included, per gram of catalyst,0.09 grams of molybdenum, 0.025 grams of nickel, and 0.01 grams ofphosphorus, with the balance being alumina support.

A molybdenum catalyst/silicon carbide mixture (12 cm³) was positioned inthe top contacting zone. The molybdenum catalyst was the same as in thetop contacting zone of Example 8.

Crude from the Mars platform (Gulf of Mexico) was filtered, then heatedin an oven at a temperature of 93° C. (200° F.) for 12-24 hours to formthe crude feed for Examples 8-11 having the properties summarized inTable 4, FIG. 12. The crude feed was fed to the top of the reactor inthese examples. The crude feed flowed through the preheat zone, topcontacting zone, bottom contacting zone, and bottom support of thereactor. The crude feed was contacted with each of the catalysts in thepresence of hydrogen gas. Contacting conditions for each example were asfollows: ratio of hydrogen gas to crude feed during contacting was 160Nm³/m³ (1000 SCFB), and the partial pressure of hydrogen of each systemwas 6.9 MPa (1014.7 psi). LHSV was 2.0 h⁻¹ during the first 200 hours ofcontacting, and then lowered to 1.0 h⁻¹ for the remaining contactingtimes. Temperatures in all contacting zones were 343° C. (650° F.) for500 hours of contacting. After 500 hours, the temperatures in allcontacting zones were controlled as follows: the temperature in thecontacting zones were raised to 354° C. (670° F.), held at 354° C. for200 hours; raised to 366° C. (690° F.), held at 366° C. for 200 hours;raised to 371° C. (700° F.), held at 371° C. for 1000 hours; raised to385° C. (725° C.), held at 385° C. for 200 hours; then raised to a finaltemperature of 399° C. (750° C.) and held at 399° C. for 200 hours, fora total contacting time of 2300 hours.

The crude products were periodically analyzed to determine TAN, hydrogenuptake by the crude feed, P-value, VGO content, residue content, andoxygen content. Average values for properties of the crude productsproduced in Examples 8-11 are listed in Table 4 in FIG. 12.

FIG. 13 is a graphical representation of P-value of the crude productversus run time for each of the catalyst systems of Examples 8-11. Thecrude feed had a P-value of at least 1.5. Plots 150, 152, 154, and 156represent the P-value of the crude product obtained by contacting thecrude feed with the four catalyst systems of Examples 8-11 respectively.For 2300 hours, the P-value of the crude product remained of at least1.5 for catalyst systems of Examples 8-10. In Example 11, the P-valuewas above 1.5 for most of the run time. At the end of the run (2300hours) for Example 11, the P-value was 1.4. From the P-value of thecrude product for each trial, it may be inferred that the crude feed ineach trial remained relatively stable during contacting (for example,the crude feed did not phase separate). As shown in FIG. 13, the P-valueof the crude product remained relatively constant during significantportions of each trial, except in Example 10, in which the P-valueincreased.

FIG. 14 is a graphical representation of net hydrogen uptake by crudefeed versus run time for four catalyst systems in the presence ofhydrogen gas. Plots 158, 160 162, 164 represent net hydrogen uptakeobtained by contacting the crude feed with each of the catalyst systemsof Examples 8-11, respectively. Net hydrogen uptake by a crude feed overa run time period of 2300 hours was in a range between 7-48 Nm³/m³(43.8-300 SCFB). As shown in FIG. 14, the net hydrogen uptake of thecrude feed was relatively constant during each trial.

FIG. 15 is a graphical representation of residue content, expressed inweight percentage, of crude product versus run time for each of thecatalyst systems of Examples 8-11. In each of the four trials, the crudeproduct had a residue content of 88-90% of the residue content of thecrude feed. Plots 166, 168, 170, 172 represent residue content of thecrude product obtained by contacting the crude feed with the catalystsystems of Examples 8-11, respectively. As shown in FIG. 15, the residuecontent of the crude product remained relatively constant duringsignificant portions of each trial.

FIG. 16 is a graphical representation of change in API gravity of thecrude product versus run time for each of the catalyst systems ofExamples 8-11. Plots 174, 176, 178, 180 represent API gravity of thecrude product obtained by contacting the crude feed with the catalystsystems of Examples 8-11, respectively. In each of the four trials, eachcrude product had a viscosity in a range from 58.3-72.7 cSt. The APIgravity of each crude products increased by 1.5 to 4.1 degrees. Theincreased API gravity corresponds to an API gravity of the crudeproducts in a range from 21.7-22.95. API gravity in this range is110-117% of the API gravity of the crude feed.

FIG. 17 is a graphical representation of oxygen content, expressed inweight percentage, of the crude product versus run time for each of thecatalyst systems of Examples 8-11. Plots 182, 184, 186, 188 representoxygen content of the crude product obtained by contacting the crudefeed with the catalyst systems of Examples 8-11, respectively. Eachcrude product had an oxygen content of at most 16% of the crude feed.Each crude product had an oxygen content in a range from 0.0014-0.0015grams per gram of crude product during each trial. As shown in FIG. 17,the oxygen content of the crude product remained relatively constantafter 200 hours of contacting time. The relatively constant oxygencontent of the crude product demonstrates that selected organic oxygencompounds are reduced during the contacting. Since TAN was also reducedin these examples, it may be inferred that at least a portion of thecarboxylic containing organic oxygen compounds are reduced selectivelyover the non-carboxylic containing organic oxygen compounds.

In Example 11, at reaction conditions of: 371° C. (700° F.), a pressureof 6.9 MPa (1014.7 psi), and a ratio of hydrogen to crude feed of 160Nm³/m³ (1000 SCFB), the reduction of crude feed MCR content was 17.5 wt%, based on the weight of the crude feed. At a temperature of 399° C.(750° F.), at the same pressure and ratio of hydrogen to crude feed, thereduction of crude feed MCR content was 25.4 wt %, based on the weightof the crude feed.

In Example 9, at reaction conditions of: 371° C. (700° F.), a pressureof 6.9 MPa (1014.7 psi), and a ratio of hydrogen to crude feed of 160Nm³/m³ (1000 SCFB), the reduction of crude feed MCR content was 17.5 wt%, based on the weight of the crude feed. At a temperature of 399° C.(750° F.), at the same pressure and ratio of hydrogen to crude feed, thereduction of crude feed MCR content was 19 wt %, based on the weight ofthe crude feed.

This increased reduction in crude feed MCR content demonstrates that theuncalcined Columns 6 and 10 metals catalyst facilitates MCR contentreduction at higher temperatures than the uncalcined Columns 6 and 9metals catalyst.

These examples demonstrate that contact of a crude feed with arelatively high TAN (TAN of 0.8) with one or more catalysts produces thecrude product, while maintaining the crude feed/total product mixturestability and with relatively small net hydrogen uptake. Selected crudeproduct properties were at most 70% of the same properties of the crudefeed, while selected properties of the crude product were within 20-30%of the same properties of the crude feed.

Specifically, as shown in Table 4, each of the crude products wasproduced with a net hydrogen uptake by the crude feeds of at most 44Nm³/m³ (275 SCFB). Such products had an average TAN of at most 4% of thecrude feed, and an average total Ni/V content of at most 61% of thetotal Ni/V content of the crude feed, while maintaining a P-value forthe crude feed of above 3. The average residue content of each crudeproduct was 88-90% of the residue content of the crude feed. The averageVGO content of each crude product was 115-117% of the VGO content of thecrude feed. The average API gravity of each crude product was 110-117%of the API gravity of the crude feed, while the viscosity of each crudeproduct was at most 45% of the viscosity of the crude feed.

Examples 12-14 Contact of a Crude Feed with Catalysts Having a Pore SizeDistribution with a Median Pore Diameter of at Least 180 Å with MinimalHydrogen Consumption

In Examples 12-14, each reactor apparatus (except for number and contentof contacting zones), each catalyst sulfiding method, each total productseparation method and each crude product analysis were the same asdescribed in Example 5. All catalysts were mixed with an equal volume ofsilicon carbide. The crude feed flow to each reactor was from the top ofthe reactor to the bottom of the reactor. Silicon carbide was positionedat the bottom of each reactor to serve as a bottom support. Each reactorcontained one contacting zone. After the catalyst/silicone carbidemixtures were placed in the contacting zone of each reactor, siliconecarbide was positioned on top of the top contacting zone to fill deadspace and to serve as a preheat zone in each reactor. Each reactor wasloaded into a Lindberg furnace that included three heating zonescorresponding to the preheat zone, the contacting zone, and the bottomsupport. The crude feed was contacted with each of the catalysts in thepresence of hydrogen gas.

A catalyst/silicon carbide mixture (40 cm³) was positioned on top of thesilicon carbide to form the contacting zone. For Example 12, thecatalyst was the vanadium catalyst as prepared in Example 2. For Example13, the catalyst was the molybdenum catalyst as prepared in Example 3.For Example 14, the catalyst was the molybdenum/vanadium catalyst asprepared in Example 4.

The contacting conditions for Examples 12-14 were as follows: ratio ofhydrogen to the crude feed provided to the reactor was 160 Nm³/m³ (1000SCFB), LHSV was 1 h⁻¹, and pressure was 6.9 MPa (1014.7 psi). Thecontacting zones were heated incrementally to 343° C. (650° F.) over aperiod of time and maintained at 343° C. for 120 hours for a total runtime of 360 hours.

Total products exited the contacting zones and were separated asdescribed in Example 5. Net hydrogen uptake during contacting wasdetermined for each catalyst system. In Example 12, net hydrogen uptakewas −10.7 Nm³/m³ (−65 SCFB), and the crude product had a TAN of 6.75. InExample 13, net hydrogen uptake was in a range from 2.2-3.0 Nm³/m³(13.9-18.7 SCFB), and the crude product had a TAN in a range from0.3-0.5. In Example 14, during contacting of the crude feed with themolybdenum/vanadium catalyst, net hydrogen uptake was in a range from−0.05 Nm³/m³ to 0.6 Nm³/m³ (−0.36 SCFB to 4.0 SCFB), and the crudeproduct had a TAN in a range from 0.2-0.5.

From the net hydrogen uptake values during contacting, it was estimatedthat hydrogen was generated at the rate of 10.7 Nm³/m³ (65 SCFB) duringcontacting of the crude feed and the vanadium catalyst. Generation ofhydrogen during contacting allows less hydrogen to be used in theprocess relative to an amount of hydrogen used in conventional processesto improve properties of disadvantaged crudes. The requirement for lesshydrogen during contacting tends to decrease the costs of processing acrude.

Additionally, contact of the crude feed with the molybdenum/vanadiumcatalyst produced a crude product with a TAN that was lower than the TANof the crude product produced from the individual molybdenum catalyst.

Examples 15-18 Contact of a Crude Feed with a Vanadium Catalyst and anAdditional Catalyst

Each reactor apparatus (except for number and content of contactingzones), each catalyst sulfiding method, each total product separationmethod, and each crude product analysis were the same as described inExample 5. All catalysts were mixed with silicon carbide in a volumeratio of 2 parts silicon carbide to 1 part catalyst unless otherwiseindicated. The crude feed flow to each reactor was from the top of thereactor to the bottom of the reactor. Silicon carbide was positioned atthe bottom of each reactor to serve as a bottom support. Each reactorhad a bottom contacting zone and a top contacting zone. After thecatalyst/silicone carbide mixtures were placed in the contacting zonesof each reactor, silicone carbide was positioned on top of the topcontacting zone to fill dead space and to serve as a preheat zone ineach reactor. Each reactor was loaded into a Lindberg furnace thatincluded four heating zones corresponding to the preheat zone, the twocontacting zones, and the bottom support.

In each example, the vanadium catalyst was prepared as described inExample 2 and used with the additional catalyst.

In Example 15, an additional catalyst/silicon carbide mixture (45 cm³)was positioned in the bottom contacting zone, with the additionalcatalyst being the molybdenum catalyst prepared by the method describedin Example 3. The vanadium catalyst/silicone carbide mixture (15 cm³)was positioned in the top contacting zone.

In Example 16, an additional catalyst/silicon carbide mixture (30 cm³)was positioned in the bottom contacting zone, with the additionalcatalyst being the molybdenum catalyst prepared by the method describedin Example 3. The vanadium catalyst/silicon carbide mixture (30 cm³) waspositioned in the top contacting zone.

In Example 17, an additional catalyst/silicone mixture (30 cm³) waspositioned in the bottom contacting zone, with the additional catalystbeing the molybdenum/vanadium catalyst as prepared in Example 4. Thevanadium catalyst/silicon carbide mixture (30 cm³) was positioned in thetop contacting zone.

In Example 18, Pyrex® (Glass Works Corporation, New York, U.S.A.) beads(30 cm³) were positioned in each contacting zone.

Crude (Santos Basin, Brazil) for Examples 15-18 having the propertiessummarized in Table 5, FIG. 18 was fed to the top of the reactor. Thecrude feed flowed through the preheat zone, top contacting zone, bottomcontacting zone, and bottom support of the reactor. The crude feed wascontacted with each of the catalysts in the presence of hydrogen gas.Contacting conditions for each example were as follows: ratio ofhydrogen gas to the crude feed provided to the reactor was 160 Nm³/m³(1000 SCFB) for the first 86 hours and 80 Nm³/m³ (500 SCFB) for theremaining time period, LHSV was 1 h⁻¹, and pressure was 6.9 MPa (1014.7psi). The contacting zones were heated incrementally to 343° C. (650°F.) over a period of time and maintained at 343° C. for a total run timeof 1400 hours.

These examples demonstrate that contact of a crude feed with a Column 5metal catalyst having a pore size distribution with a median porediameter of 350 Å in combination with an additional catalyst having apore size distribution with a median pore diameter in a range from250-300 Å, in the presence of a hydrogen source, produces a crudeproduct with properties that are changed relative to the same propertiesof crude feed, while only changing by small amounts other properties ofthe crude product relative to the same properties of the crude feed.Additionally, during processing, relatively small hydrogen uptake by thecrude feed was observed.

Specifically, as shown in Table 5, FIG. 18, the crude product has a TANof at most 15% of the TAN of the crude feed for Examples 15-17. Thecrude products produced in Examples 15-17 each had a total Ni/V/Fecontent of at most 44%, an oxygen content of at most 50%, and viscosityof at most 75% relative to the same properties of the crude feed.Additionally, the crude products produced in Examples 15-17 each had anAPI gravity of 100-103% of the API gravity of the crude feed.

In contrast, the crude product produced under non-catalytic conditions(Example 18) produced a product with increased viscosity and decreasedAPI gravity relative to the viscosity and API gravity of the crude feed.From the increased viscosity and decreased API gravity, it may bepossible to infer that coking and/or polymerization of the crude feedwas initiated.

Examples 19 Contact of a Crude Feed at Various LHSV

The contacting systems and the catalysts were the same as described inExample 6. The properties of the crude feeds are listed in Table 6 inFIG. 19. The contacting conditions were as follows: a ratio of hydrogengas to the crude feed provided to the reactor was 160 Nm³/m³ (1000SCFB), pressure was 6.9 MPa (1014.7 psi), and temperature of thecontacting zones was 371° C. (700° F.) for the total run time. InExample 19, the LHSV during contacting was increased over a period oftime from 1 h⁻¹ to 12 h⁻¹, maintained at 12 h⁻¹ for 48 hours, and thenthe LHSV was increased to 20.7 h⁻¹ and maintained at 20.7 h⁻¹ for 96hours.

In Example 19, the crude product was analyzed to determine TAN,viscosity, density, VGO content, residue content, heteroatoms content,and content of metals in metal salts of organic acids during the timeperiods that the LHSV was at 12 h⁻¹ and at 20.7 h⁻¹. Average values forthe properties of the crude products are shown in Table 6, FIG. 19.

As shown in Table 6, FIG. 19, the crude product for Example 19 had areduced TAN and a reduced viscosity relative to the TAN and theviscosity of the crude feed, while the API gravity of the crude productwas 104-110% of the API gravity of the crude feed. A weight ratio of MCRcontent to C₅ asphaltenes content was at least 1.5. The sum of the MCRcontent and C₅ asphaltenes content was reduced relative to the sum ofthe MCR content and C₅ asphaltenes content of the crude feed. From theweight ratio of MCR content to C₅ asphaltenes content and the reducedsum of the MCR content and the C₅ asphaltenes, it may be inferred thatasphaltenes rather than components that have a tendency to form coke arebeing reduced. The crude product also had total content of potassium,sodium, zinc, and calcium of at most 60% of the total content of thesame metals of the crude feed. The sulfur content of the crude productwas 80-90% of the sulfur content of the crude feed.

Examples 6 and 19 demonstrate that contacting conditions can becontrolled such that a LHSV through the contacting zone is greater than10 h⁻¹, as compared to a process that has a LHSV of 1 h⁻¹, to producecrude products with similar properties. The ability to selectivelychange a property of a crude feed at liquid hourly space velocitiesgreater than 10 h⁻¹ allows the contacting process to be performed invessels of reduced size relative to commercially available vessels. Asmaller vessel size may allow the treatment of disadvantaged crudes tobe performed at production sites that have size constraints (forexample, offshore facilities).

Example 20 Contact of a Crude Feed at Various Contacting Temperatures

The contacting systems and the catalysts were the same as described inExample 6. The crude feed having the properties listed in Table 7 inFIG. 20 was added to the top of the reactor and contacted with the twocatalysts in the two contacting zones in the presence of hydrogen toproduce a crude product. The two contacting zones were operated atdifferent temperatures.

Contacting conditions in the top contacting zone were as follows: LHSVwas 1 h⁻¹; temperature in the top contacting zone was 260° C. (500° F.);a ratio of hydrogen to crude feed was 160 Nm³/m³ (1000 SCFB); andpressure was 6.9 MPa (1014.7 psi).

Contacting conditions in the bottom contacting zone were as follows:LHSV was 1 h⁻¹; temperature in the bottom contacting zone was 315° C.(600° F.); a ratio of hydrogen to crude feed was 160 Nm³/m³ (1000 SCFB);and pressure was 6.9 MPa (1014.7 psi).

The total product exited the bottom contacting zone and was introducedinto the gas-liquid phase separator. In the gas-liquid phase separator,the total product was separated into the crude product and gas. Thecrude product was periodically analyzed to determine TAN and C₅asphaltenes content.

Average values for the properties of crude product obtained during therun are listed in Table 7, FIG. 20. The crude feed had a TAN of 9.3 anda C₅ asphaltenes content of 0.055 grams of C₅ asphaltenes per gram ofcrude feed. The crude product had an average TAN of 0.7 and an averageC₅ asphaltenes content of 0.039 grams of C₅ asphaltenes per gram ofcrude product. The C₅ asphaltenes content of the crude product was atmost 71% of the C₅ asphaltenes content of the crude product.

The total content of potassium and sodium in the crude product was atmost 53% of the total content of the same metals in the crude feed. TheTAN of the crude product was at most 10% of the TAN of the crude feed. AP-value of 1.5 or higher was maintained during contacting.

As demonstrated in Examples 6 and 20, having a first (in this case, top)contacting temperature that is 50° C. lower than the contactingtemperature of the second (in this case, bottom) zone tends to enhancethe reduction of C₅ asphaltenes content in the crude product relative tothe C₅ asphaltenes content of the crude feed. Additionally, reduction ofthe content of metals in metal salts of organic acids was enhanced usingcontrolled temperature differentials. For example, reduction in thetotal potassium and sodium content of the crude product from Example 20was enhanced relative to the reduction of the total potassium and sodiumcontent of the crude product from Example 6 with a relatively constantcrude feed/total product mixture stability for each example, as measuredby P-value.

Using a lower temperature of a first contacting zone allows removal ofthe high molecular weight compounds (for example, C₅ asphaltenes and/ormetals salts of organic acids) that have a tendency to form polymersand/or compounds having physical properties of softness and/orstickiness (for example, gums and/or tars). Removal of these compoundsat lower temperature allow such compounds to be removed before they plugand coat the catalysts, thereby increasing the life of the catalystsoperating at higher temperatures that are positioned after the firstcontacting zone.

Example 21 Contact of a Crude Feed with at Least One Catalyst Having aPore Size Distribution with a Median Pore Diameter of at Least 180 Å forGreater than 500 Hours

The reactor apparatus (except for number and content of contactingzones), the total product separation method, crude product analysis, thecatalysts and catalyst sulfiding method were the same as described inExample 5.

A molybdenum catalyst (11.25 cm³) prepared by the method described inExample 3 and mixed with silicon carbide (22.50 cm³) to form amolybdenum catalyst/silicon carbide mixture (37.75 cm³) was positionedin the bottom contacting zone. A vanadium catalyst (3.75 cm³) preparedby the method described in Example 4 was mixed with silicon carbide (7.5cm³) to form a vanadium catalyst/silicone carbide mixture (11.25 cm³)was positioned in the top contacting zone.

A crude feed (BC-10 crude) having the properties summarized in Table 8,FIG. 21, was fed to the top of the reactor. The crude feed flowedthrough the preheat zone, top contacting zone, bottom contacting zone,and bottom support of the reactor. The contacting conditions were asfollows: ratio of hydrogen gas to the crude feed provided to the reactorwas 160 Nm³/m³ (1000 SCFB), LHSV was 2 h⁻¹, and pressure was 3.4 MPa(500 psig). The two contacting zones were heated incrementally to 343°C. (650° F.).

After total run time of 1175 hours, the crude product had a TAN of 0.44and an API gravity of 15.9. The crude product had 0.6 wtppm of calcium,0.8 wtppm of sodium, 0.9 wtppm of zinc, 1.5 wtppm of potassium, 0.8wtppm silicon. The crude product had, per gram of crude product, 0.0043grams of sulfur, 0.003 grams of oxygen, 0.407 grams of VGO, and 0.371grams of residue. Additional properties of the crude product are listedin Table 8 in FIG. 21.

After total run time of 5207 hours with no catalyst replacement, thecrude product had a TAN of 0.27 and an API gravity of 15.7. The crudeproduct had 0.4 wtppm of calcium, 1.1 wtppm of sodium, 0.9 wtppm ofzinc, and 1.7 wtppm of potassium. The crude product had, per gram ofcrude product, 0.00396 grams of sulfur, 0.407 grams of VGO, and 0.38grams of residue. Additional properties of the crude product are listedin Table 8 in FIG. 21.

This example demonstrates that contacting of the crude feed with theselected catalysts and at least one of the catalysts having a pore sizedistribution with a median pore diameter of greater than 180 Å produceda crude product that had a reduced TAN, a reduced total calcium, sodium,zinc, potassium and silicon content while sulfur content, VGO content,and residue content of the crude product were 100%, 102%, and 95.6% ofthe respective properties of the crude feed. This example alsodemonstrates that the TAN of the crude product is at least 30% of theTAN of the crude feed after 500 hours without replacement of thecatalysts. This example also demonstrates that one or more properties ofthe crude feed may be changed at a lower pressure, higher throughput atelevated temperatures. This example also demonstrates that a Column 6metal catalyst that exhibits bands between 810 cm⁻¹ to 870 cm⁻¹ asdetermined by Raman Spectroscopy produces a total product that includesa crude product with a TAN that is at least 90% of the TAN of the crudefeed.

Example 22 Contact of a Crude Feed and a Catalyst in an ContinuouslyStirred Reactor (CSTR)

A molybdenum catalyst (25.5 grams, 50 cm⁻³) prepared as in Example 3 wascharged to a CSTR. Crude feed (BS-4) having the properties listed inTable 9 in FIG. 22 was metered at a flow rate of 24.1 g/hr to produce aLHSV of 0.5 h⁻¹. A temperature 421° C. (790° F.), a partial pressure ofhydrogen of 14 MPa (2000 psig), and ratio of hydrogen source to crudefeed of 320 Nm³/m³ (2000 SCFB) were maintained through out the run.Total product was removed from the top of the reactor and separated intocrude product and process gases. During the run, an amount of sedimentwas monitored to determine if the reaction vessel was filling withimpurities and/or coke. The amount of sediment, per gram of crude feed,ranged between 0.0001 grams and 0.00013 grams during the run.

Properties of the crude product after 286 hours are tabulated in Table 9of FIG. 22. The crude product had a TAN of 0.26 and an API gravity of21.2. The crude product had 2.2 wtppm of calcium, 0.2 wtppm of sodium,6.4 wtppm of zinc, 0.7 wtppm of silicon, 0.2 wtppm of potassium, 2.9wtppm nickel, 0.6 wtppm vanadium, and 2.3 wtppm iron. The crude producthad, per gram of crude product, 0.018 grams of sulfur, 0.386 ofdistillate, 0.41 grams of VGO, and 0.204 grams of residue.

This example demonstrates that contact of a crude feed with hydrogen inthe presence of at least one molybdenum catalyst that exhibits bands inthe range 810 cm⁻¹ to 870 cm⁻¹ as determined by Raman Spectroscopyproduces a total product that includes a crude product with a residuecontent of at least 90% of the residue content of the crude feed. Thisexample also demonstrates that contact of a crude feed with hydrogen inthe presence of at least one molybdenum catalyst that exhibits bands inthe range 810 cm⁻¹ to 870 cm⁻¹ as determined by Raman Spectroscopyproduces a total product that includes a crude product with a TAN thatis at least 90% of the TAN of the crude feed.

Comparative Example 23 Contact of a Crude Feed and a Catalyst in anContinuously Stirred Reactor (CSTR)

The reactor apparatus, the total product separation method, crudeproduct analysis, and catalyst sulfiding method were the same asdescribed in Example 22. The catalyst had a pore size distribution witha median pore diameter of 192 Å and contained 0.04 grams of molybdenumper gram of catalyst, with the balance being primarily a gamma aluminasupport. The catalyst did not exhibit absorption in the range Δ810 cm⁻¹to Δ870 cm⁻¹ as determined by Raman Spectroscopy. The properties of thecrude product after 213 hours are tabulated in Table 9 of FIG. 22. At213 hours a content of sediment, per gram of crude feed, was 0.0019grams, per gram of crude feed/total product. After 765 hours thesediment had increased to 0.00329 grams, per gram of crude feed/totalproduct. An increase in sediment relative to sediment content of thecrude feed/total product mixture when contacting the crude feed with themolybdenum catalyst of Example 22 indicates that impurities and/or cokeare forming at an increased rate. An increased rate of sedimentformation decreases contacting time and/or catalyst life, thus thecatalyst of Example 22 has a longer catalyst life than the catalyst ofExample 23.

Example 24 Preparation of a Columns 6-10 Metal(s) Catalyst Having atLeast 10 Wt % Molybdenum

A support (200 grams) that contained 0.02 grams of silica-alumina and0.98 grams alumina per gram of support was impregnated with amolybdenum/nickel solution. A first solution was prepared by combining62.34 grams of (NH₄)₂Mo₂O₇ and 17.49 grams of MoO₃, 3 grams ofmonoethanolamine, 12.22 grams of 30% hydrogen peroxide, and 50.47 gramsof deionized water to form a slurry. The slurry was heated to 63.8° C.(147° C.) until dissolution of the solids. The solution was cooled toroom temperature. The pH of the solution was 5.34.

A second solution was prepared by combining 31.93 grams ofNi(NO₃)₈.6H₂O, 9.63 grams of NiCO₃, and 30.56 grams of deionized waterto form a slurry. Concentrated phosphoric acid (39.57 grams of 85.9 wt %H₃PO₄) was added at a rate sufficient to control foaming. The solutionwas stirred until the solids were dissolved. The pH of the solution was0.29.

The first solution and second solution were combined and sufficientdeionized water was added to bring the combined solution volume up to218.75 mL to yield the molybdenum/nickel impregnation solution. The pHof the resulting solution was 2.02. The support was impregnated with themolybdenum/nickel solution, aged for several hours with occasionalagitation, dried at 125° C. for several hours, and then calcined at 482°C. (900° F.) for two hours. The resulting catalyst contained, per gramof catalyst, 0.13 grams of Mo, 0.03 grams Ni, 0.005 grams of phosphoruswith the balance being support. The molybdenum/nickel catalyst had amedian pore diameter of 155 Å, with at least 60% of the total number ofpores in the pore sized distribution having a pore diameter within 28 Åof the median pore diameter, a pore volume of 0.84 mL/g, and a surfacearea of 179 m²/g.

Example 25 Contact of a Hydrocarbon Feed with Two Catalysts at aPressure of at Most 7 MPa

The reactor apparatus (except for number and content of contactingzones), the total product separation method, crude product analysis, andcatalyst sulfiding method were the same as described in Example 6.

A catalyst as prepared in Example 24, (12.5 cm³) was mixed with siliconcarbide (12.5 cm³) to form a molybdenum catalyst/silicon carbide mixtureand was positioned in the bottom contacting zone.

A molybdenum catalyst (12.5 cm³) containing 0.039 grams of molybdenum,0.01 grams of nickel and 0.0054 grams of phosphorus with the balancebeing alumina and having a median pore diameter of 108 Å and a surfacearea of 266 m²/g was mixed with silicon carbide (12.5 cm³) to form amolybdenum catalyst/silicon carbide mixture and was positioned in thetop contacting zone.

After sulfidation of the catalysts, the contacting zones were raised toa temperature of 385° C. A heated hydrocarbon feed (Peace River crude)having the properties summarized in Table 10, FIG. 23 was fed to the topof the reactor. The hydrocarbon feed flowed through the preheat zone,top contacting zone, bottom contacting zone, and bottom support of thereactor. The hydrocarbon feed was contacted with each of the catalystsin the presence of hydrogen gas. Contacting conditions were as follows:ratio of hydrogen gas to feed was 328 Nm³/m³ (2000 SCFB) and LHSV was0.5 h⁻¹. The two contacting zones were heated to 385° C. at a pressureof 13.8 MPa (2000 psig) and the hydrocarbon feed flowed through thecontacting zones for 600 hours. Temperatures and pressures for the twocontacting zones were then adjusted and maintained in the followingsequence: 400° C., 6.9 MPa (1000 psig) for 1203 hours; 410° C., 3.8 MPa(500 psig) for 1149 hours. The total contact time for the two catalystswas 2952 hours.

As shown in FIG. 23, contact of the hydrocarbon feed at pressures of atmost 7 MPa and temperatures of at least 300° C., produced a crudeproduct that had a molybdenum content of 0.4 wtppm, a Ni/V/Fe content of251 wtppm, a residue content of 0.275 grams per gram of crude product, aC₅/C₇ asphaltenes content of 15.4 wt %, and a viscosity of 74.4 cSt at37.8° C. During the run at lower temperatures the P value of thefeed/intermediate product was 1.2. The total amount of C₁-C₄ gasproduced during contacting was at most 0.02 grams per gram of totalproduct.

As shown in Table 10 of FIG. 23, contact of the feed at controlledcontacting conditions of at most 7 MPa and at least 300° C., themolybdenum content was at most 90% of the feed molybdenum content, theNi/V/Fe content was between 80% and 120% of the feed Ni/V/Fe content,C₅/C₇ asphaltenes content was at most 90% of the C₅/C₇ feed asphaltenescontent, the residue was at most 90% of the feed residue and theviscosity was at most 90% of the feed viscosity. As shown in FIG. 23,the crude product has at least 0.1 wtppm of molybdenum, at least 0.01grams of hydrocarbons having a boiling range distribution between 38° C.and 200° C. per gram of hydrocarbon composition; and at least 0.1 gramsof hydrocarbons having a boiling range distribution between 343° C. and650° C. per gram of hydrocarbon composition. The crude product also hasat least 0.001 grams of hydrocarbons with a boiling range distributionbetween 38° C. and 200° C. at 0.101 MPa; at least 0.001 grams ofhydrocarbons with a boiling range distribution between 204° C. and 343°C. at 0.101 MPa; at least 0.001 grams of hydrocarbons with a boilingrange distribution between 343° C. and 650° C. at 0.101 MPa; at least0.001 grams of hydrocarbons with an initial boiling point of at least650° C. at 0.101 MPa; at least 0.000150 grams of Ni/V/Fe; and at most0.01 grams of C₅ asphaltenes.

This example also demonstrates that at the P-value of a hydrocarbonfeed/total product mixture remains above 1.0 at pressures when thehydrocarbon feed is contacted with the catalysts at a pressure of atmost 7 MP, at temperatures ranging from 350° C. and 450° C., and at aLHSV of at least 0.1 h⁻¹.

Example 25 also demonstrates that at operating conditions of at most 7MPa and temperatures of at most 450° C., the viscosity of the crudeproduct is at most 50% of the hydrocarbon feed while the consumption ofhydrogen is at most 80 Nm³/m³.

Example 26 Preparation of Column 6 Metal(s) Catalyst Containing MineralOxide Fines

The catalyst was prepared in the following manner. MoO₃ (99.44 grams)was combined with 2 wide pore alumina (737.85 grams) and crushed andsieved alumina fines having a particle size between 5 and 10 micrometers(1050.91 grams) in a muller. With the muller running, 43.04 grams of69.7 wt % nitric acid, 4207.62 grams of deionized water were added tothe mixture and the resulting mixture was mulled for 5 minutes.Superfloc® 16 (30 grams, Cytec Industries, West Paterson, N.J., USA) wasadded to the mixture in the muller, and the mixture was mulled for attotal of 25 minutes. The resulting mixture had a pH of 6.0 and an LOI of0.6232 grams per gram of mixture. The mulled mixture was extruded using1.3 mm trilobe dies to form 1.3 trilobe extrudate particles. Theextrudate particles were dried at 125° C. for several hours and thencalcined at 676° C. (1250° F.) for two hours. The catalyst contained0.02 grams of molybdenum, with the balance being mineral oxide andsupport. The catalyst had a pore size distribution with a median porediameter of 117 Å with 66.7% of the total number of pores in the poresize distribution having a pore diameter within 33 Å of the median porediameter, and a total pore volume of 0.924 ml/g.

The pore size distribution at theta=140° as a percentage of total poreswas as follows: <70 Å 0.91%; 70-100 Å 20.49%; 100-130 Å 37.09%; 130-150Å 4.51%; 150-180 Å 2.9%; 150-180 Å 2.9%; 180-200 Å 1.06%; 200-1000 Å0.85%, 1000-5000 Å 5.79% and >5000 Å 22.04%.

This example demonstrates a catalyst that includes a support, mineraloxides, and one or more metals from Column 6 of the Periodic Tableand/or one or more compounds of one or more metals from Column 6 of thePeriodic Table. The catalyst has a pore size distribution with a medianpore diameter of at least 80 Å and the catalyst is obtainable bycombining: a mineral oxide fines; the one or more of metals from Column6 of the Periodic Table and/or the one or more compounds of one or moremetals from Column 6 of the Periodic Table; and a support.

Example 27 Contact of a Hydrocarbon Feed with a Column 6 Metal(s)Catalyst Having Mineral Oxide Fines

The reactor apparatus (except for number and content of contactingzones), the total product separation method, crude product analysis, andcatalyst sulfiding method were the same as described in Example 5.

A molybdenum catalyst as described in Example 26 was mixed with siliconcarbide (total volume of 30 cm³) and was positioned in the bottomcontacting zone. A molybdenum catalyst as described in Example 26 wasmixed with silicon carbide (total volume of 30 cm³) and was positionedin the top contacting zone.

After sulfidation of the catalysts, the temperature of the contactingzones was raised to a temperature of 400° C. A hydrocarbon feed (PeaceRiver) having the properties listed in Table 10, FIG. 23. Thehydrocarbon feed flowed through the preheat zone, top contacting zone,bottom contacting zone, and bottom support of the reactor. Thehydrocarbon feed was contacted with each of the catalysts in thepresence of hydrogen gas. Contacting conditions were as follows: ratioof hydrogen gas to feed was 318 Nm³/m³ (2000 SCFB) and LHSV was 0.5 h⁻¹.The two contacting zones were heated to 400° C. and maintained between400° C. and 402° C. at a pressure of 3.8 MPa (500 psig) for 671 hours asthe hydrocarbon feed flowed through the reactor.

As shown in Table 10, FIG. 23, the crude product had a viscosity of 53.1at 37.8° C., a residue content of 0.202 grams, per gram of catalyst, aNi/V/Fe content of 164 wtppm and a molybdenum content of 0.5 wtppm.

This example demonstrates that contact of a hydrocarbon feed with aColumn 6 metal catalyst that is obtainable by combining mineral oxidefines, one or more metals from Columns 6 of the Periodic Table and/orone or more compounds of one or more metals from Columns 6 of thePeriodic Table; and a support produces a crude product having a residuecontent of at most 90% of hydrocarbon feed residue. This example alsodemonstrates that contact of a hydrocarbon feed with a Column 6 metalcatalyst that is obtainable by combining mineral oxide fines, one ormore metals from Columns 6 of the Periodic Table and/or one or morecompounds of one or more metals from Columns 6 of the Periodic Table;and a support produces a crude product having a viscosity content of atmost 50% of hydrocarbon feed viscosity at 37.8° C.

Example 28 Contact of a Hydrocarbon Feed with One Catalyst

In a separate experiment, the hydrocarbon feed was contacted with thecatalyst as prepared in Example 24 at the same conditions as describedin Example 25 and in the absence of the top catalyst described inExample 25. After approximately 45 hours of passing hydrocarbon feedthrough the reactor, the catalyst bed plugged. This example demonstratesthat the top catalyst used in Example 25 removes at least a portion ofthe compounds (for example, molybdenum compounds) that contribute tocatalyst plugging.

Example 29 Contact of a Hydrocarbon Feed with a Column 6 Metal(s)Catalyst

The reactor apparatus (except for number and content of contactingzones), the total product separation method, crude product analysis, andcatalyst sulfiding method were the same as described in Example 5.

A molybdenum catalyst (27.5 cm³) as prepared in Example 24 (3 cm³) toform a molybdenum catalyst/silicon carbide mixture was positioned in thebottom contacting zone.

A molybdenum/vanadium catalyst (3 cm³) prepared by the method describedin Example 4 and mixed with silicon carbide (3 cm³) to form amolybdenum/vanadium catalyst/silicon carbide mixture (37.75 cm³) waspositioned in the top contacting zone.

After sulfidation of the catalysts, the temperature of the contactingzones was raised to a temperature of 385° C. A hydrocarbon feed (BC-10)having the properties summarized in Table 11, FIG. 24 was fed to the topof the reactor. The hydrocarbon feed flowed through the preheat zone,top contacting zone, bottom contacting zone, and bottom support of thereactor. The hydrocarbon feed was contacted with each of the catalystsin the presence of hydrogen gas. Contacting conditions were as follows:ratio of hydrogen gas to feed was 328 Nm³/m³ (2000 SCFB) and LHSV was0.5 h⁻¹. The two contacting zones were heated to 390° C. at a pressureof 15.9 MPa (2300 psig) and the hydrocarbon feed flowed through thereactor for 4703 hours. During contacting the P-value of the hydrocarbonfeed/total product mixture remained above 1.0.

As shown in FIG. 24, the crude product had, per gram of crude product,0.0665 grams of basic nitrogen, 0.241 grams of residue, 0.063 grams oftotal C₅/C₇ asphaltenes, a MCR content of 0.037 grams, and a viscosityof 45 cSt at 37.8° C.

This example demonstrates that contact of a hydrocarbon feed with acatalyst having a pore size distribution with a median pore diameter ofbetween 50 angstroms and 180 angstroms produces a crude product having abasic nitrogen content of at most 90% of the hydrocarbon feed basicnitrogen content. This example also demonstrates that contact of ahydrocarbon feed with a catalyst having Columns 6 and 9 metal(s)produces a crude product having a MCR content of at most 90% of the MCRcontent of the hydrocarbon feed.

Example 30 Preparation of a Catalyst

The Catalyst was Prepared in the Following Manner. A nickel solution wasmade by combining 286.95 grams of Ni(NO₃).6H₂O, and 99.21 grams ofdeionized water to form a slurry. The slurry was heated until clear. Asupport (3208.56 grams) that contained 0.02 grams of silica-alumina and0.98 grams alumina per gram of support was combined with the nickelsolution, a Ni—Mo—P used catalyst (652.39 grams), and MoO₃ (268.85grams) in a muller. During mulling, HNO₃ (128.94 grams 69.9 wt %) anddeionized water (2948.29 grams) was added to the mixture and the mixturewas mulled for 40 minutes. Superfloc® 16 (30 grams) was added to themixture and the mixture was mulled for 5 minutes. The resulting mixturehad a pH of 4.18 and a LOI of 0.557 grams per gram of mixture.

The mulled mixture was extruded using 1.3 mm trilobe dies to form 1.3trilobe extrudate particles. The extrudates were dried at 100° C. forseveral hours and then calcined at 676.6° C. (1250° F.) for two hours.The resulting catalyst contained, per gram of catalyst, 0.079 grams ofMo, and 0.022 grams Ni, with the balance being used catalyst andsupport. The molybdenum/nickel catalyst had a median pore diameter of 96Å, with at least 60% of the total number of pores in the pore sizedistribution having a pore diameter within 39 Å of the median porediameter, a pore volume of 0.596 mL/g, and a surface area of 256 m²/g.

Example 31 Contact of a Hydrocarbon Feed with the Catalyst

The reactor apparatus (except for number and content of contactingzones), the total product separation method, crude product analysis, andcatalyst sulfiding method were the same as described in Example 5.

A molybdenum catalyst (27 cm³) as described in Example 30 was mixed withsilicon carbide (3 cm³) and was positioned in the bottom contactingzone.

A molybdenum/vanadium catalyst (3 cm³) prepared by the method describedin Example 4 was mixed with silicon carbide (3 cm³) to form amolybdenum/vanadium catalyst/silicon carbide mixture (37.75 cm³) and waspositioned in the top contacting zone.

After sulfidation of the catalysts, the contacting zones were raised toa temperature of 385° C. A hydrocarbon feed (BC-10) having theproperties summarized in Table 11, FIG. 24 was fed to the top of thereactor. The hydrocarbon feed flowed through the preheat zone, topcontacting zone, bottom contacting zone, and bottom support of thereactor. The feed was contacted with each of the catalysts in thepresence of hydrogen gas. Contacting conditions were as follows: ratioof hydrogen gas to feed was 328 Nm³/m³ (2000 SCFB) and LHSV was 0.5 h⁻¹.The two contacting zones were heated to 390° C. at a pressure of 15.9MPa (2300 psig) as the hydrocarbon feed flowed through the contactingzone for 4703 hours. During contacting the P-value of the hydrocarbonfeed/total product mixture remained above 1.0.

As shown in FIG. 24, the crude product had, per gram of crude productand 0.255 grams of residue and a viscosity of 48.7 cSt at 37.8° C.

This example demonstrates that contact of a hydrocarbon feed with acatalyst prepared by combining a used catalyst, Columns 6-10 metals, anda support produces a crude product having residue content of at most 90%of hydrocarbon feed residue.

Example 32 Preparation of a Columns 6 and 10 Metal(s) Catalyst

The catalyst was prepared in the following manner. A nickel solution wasmade by combining 377.7 grams of Ni(NO₃), and 137.7 grams of deionizedwater to form a slurry. The slurry was heated until clear and sufficientdeionized water was added to bring the combined nickel solution weightup the 3807 grams. MoO₃ (417.57 grams) was combined with 4047.49 gramsof support containing 0.02 grams of A nickel solution was made bycombining 286.95 grams of Ni(NO₃).6H₂O, and 99.21 grams of deionizedwater to form a slurry. The slurry was heated until clear. A support(3208.56 grams) that contained 0.02 grams of silica-alumina and 0.98grams alumina per gram of support was combined with the nickel solutionand MoO₃ (417.57 grams) in a muller. During mulling, 4191.71 deionizedwater was added to the mixture and the mixture was mulled for 45minutes. The resulting mixture had a pH of 4.75 and a LOI of 0.596 gramsper gram of mixture.

The mulled mixture was extruded using 1.3 mm trilobe dies to form 1.3trilobe extrudate particles. The extrudates were dried at 100° C. forseveral hours and then calcined at 537.7° C. (1000° F.) for two hours.The resulting catalyst contained, per gram of catalyst, 0.079 grams ofMo, and 0.022 grams Ni, with the balance being support. Themolybdenum/nickel catalyst had a median pore diameter of 67 Å, with atleast 60% of the total number of pores in the pore size distributionhaving a pore diameter with 25 Å of the median pore diameter, a porevolume of 0.695 mL/g, and a surface area of 268 m²/g.

Example 33 Contact of a Hydrocarbon Feed with a Columns 6 and 10Metal(s) Catalyst

The reactor apparatus (except for number and content of contactingzones), the total product separation method, crude product analysis, andcatalyst sulfiding method were the same as described in Example 5.

A molybdenum/nickel catalyst (27 cm³) as described in Example 32 wasmixed with silicon carbide (3 cm³) and was positioned in the bottomcontacting zone.

A molybdenum/vanadium catalyst (3 cm³) prepared by the method describedin Example 4 was mixed with silicon carbide (3 cm³) to form amolybdenum/vanadium catalyst/silicon carbide mixture (37.75 cm³) and waspositioned in the top contacting zone.

After sulfidation of the catalysts, the contacting zones were raised toa temperature of 385° C. A hydrocarbon feed (BC-10) having theproperties summarized in Table 11, FIG. 24 was fed to the top of thereactor. The hydrocarbon feed flowed through the preheat zone, topcontacting zone, bottom contacting zone, and bottom support of thereactor. The feed was contacted with each of the catalysts in thepresence of hydrogen gas. Contacting conditions were as follows: ratioof hydrogen gas to feed was 328 Nm³/m³ (2000 SCFB) and LHSV was 0.5 h⁻¹.The two contacting zones were heated to 390° C. at a pressure of 15.9MPa (2300 psig) as the hydrocarbon feed passed through the contactingzones for 4703 hours. During contacting the P-value of the hydrocarbonfeed/total product mixture remained above 1.0.

As shown in FIG. 24, the crude product had, per gram of crude product0.235 grams of residue and a viscosity of 41.8 cSt at 37.8° C.

This example demonstrates that contact of a hydrocarbon feed with acatalyst that has or more metals from Column 6 of the Periodic Tableand/or one or more compounds of one or more metals from Column 6 of thePeriodic Table; and one or more metals from Columns 9-10 of the PeriodicTable and/or one or more compounds of one or more metals from Columns9-10 of the Periodic Table and having a pore size distribution with amedian pore diameter between 50 Å and 120 Å produces a crude producthaving a residue content of at most 90% of the hydrocarbon feed residue.

Example 34 Preparation of a Dried Catalyst

The dried catalyst was prepared in the following manner. A support (200grams) that contained 0.02 grams of 0.01 grams of nickel and 0.99 gramsalumina per gram of support was impregnated with a molybdenum/cobaltsolution. The solution was prepared by combining 46.68 grams of MoO₃,14.07 grams of Co(OH)₂, 20.08 grams of 85% H₃PO₄, and 300 grams ofdeionized water to form a slurry. The slurry was and heated to 93.3° C.(200° C.) until dissolution of the solids and then further heated untilvolume of the solution was reduced to 166 mL The solution was thencooled to room temperature. The pH of the solution was 1.71.

The support was impregnated with the molybdenum/cobalt solution, agedfor several hours with occasional agitation and dried at 100° C. forseveral hours (overnight). The resulting catalyst contained, per gram ofcatalyst, 0.115 grams of Mo, 0.032 grams Co, 0.02 grams of phosphorus,and 0.74 grams of Ni with the balance being support. Themolybdenum/cobalt/nickel catalyst had a LOI of 0.053 grams per gram ofcatalyst.

Example 35 Contact of a Hydrocarbon Feed with a Dried Catalyst

The reactor apparatus (except for number and content of contactingzones), the total product separation method, and the crude productanalysis were the same as described in Example 5.

A molybdenum catalyst (33.34 cm³) as described in Example 34 was mixedwith silicon carbide (33.34 cm³) and positioned in the bottom contactingzone.

A molybdenum catalyst (16.67 cm³) having a pore size distribution with amedian pore diameter of 192 Å and containing 0.04 grams of molybdenumper gram of catalyst, with the balance being primarily a gamma aluminasupport was mixed with silicon carbide (16.67 cm³) and positioned in thetop contacting zone.

The catalysts were sulfided using the method as described in U.S. Pat.No. 6,290,841 to Gabrielov et al. After sulfidation of the catalysts,the temperature of the contacting zones was raised to a temperature of405° C. A hydrocarbon feed (Kuwait long residue) having the propertiessummarized in Table 12, FIG. 25 was fed to the top of the reactor. Thehydrocarbon feed flowed through the preheat zone, top contacting zone,bottom contacting zone, and bottom support of the reactor. Thehydrocarbon feed was contacted with each of the catalysts in thepresence of hydrogen gas. Contacting conditions were as follows: ratioof hydrogen gas to feed was 656 Nm³/m³ (4000 SCFB) and LHSV was 0.33h⁻¹. The two contacting zones were heated to 390° C. at a pressure of13.13 MPa (1900 psig) as the hydrocarbon feed flowed through thecontacting zones for 2537 hours. During contacting the P-value of thehydrocarbon feed/total product mixture remained above 1.0.

As shown in Table 12, FIG. 25, the crude product had a viscosity of 63.5cSt at 37.8° C. and, 0.243 grams of residue and C₅ asphaltenes contentof 0.024 grams per gram of crude product.

This example demonstrates that contact of a hydrocarbon feed with adried catalyst produces a crude product having a residue content of atmost 90% of hydrocarbon feed residue.

Further modifications and alternative embodiments of various aspects ofthe invention will be apparent to those skilled in the art in view ofthis description. Accordingly, this description is to be construed asillustrative only and is for the purpose of teaching those skilled inthe art the general manner of carrying out the invention. It is to beunderstood that the forms of the invention shown and described hereinare to be taken as examples of embodiments. Elements and materials maybe substituted for those illustrated and described herein, parts andprocesses may be reversed and certain features of the invention may beutilized independently, all as would be apparent to one skilled in theart after having the benefit of this description of the invention.Changes may be made in the elements described herein without departingfrom the spirit and scope of the invention as described in the followingclaims.

1. A method of producing a crude product, comprising: contacting ahydrocarbon feed with one or more catalysts to produce a total productthat includes the crude product, wherein the crude product is a liquidmixture at 25° C. and 0.101 MPa, the hydrocarbon feed having a basicnitrogen content of at least 0.0001 grams per gram of hydrocarbon feed,at least one of the catalysts has at least 0.01 grams of one or moremetals from Column 6 of the Periodic Table and/or one or more compoundsof one or more metals from Column 6 of the Periodic Table per gram ofcatalyst, the Column 6 metal catalyst having a pore size distributionwith median pore diameter of between 50 angstroms and 180 angstroms;controlling contacting conditions at a pressure of at least 3 MPa and atemperature of at least 300° C. to produce the crude product, the crudeproduct having a basic nitrogen content of at most 90% of the basicnitrogen content of the hydrocarbon feed and wherein basic nitrogen isas determined by ASTM Method D2896.
 2. The method of claim 1, whereinthe Column 6 metal catalyst comprises molybdenum.
 3. The method of claim1, wherein the Column 6 metal catalyst comprises at most 0.1 grams ofmolybdenum per gram of catalyst.
 4. The method of claim 1, wherein theColumn 6 metal catalyst is a supported catalyst, and wherein the supportcomprises alumina, silica, silica-alumina, titanium oxide, zirconiumoxide, magnesium oxide, or mixtures thereof.
 5. The method of claim 1,wherein the Column 6 metal catalyst has a pore size distribution with amedian pore diameter from 55 angstroms to 150 angstroms, from 60angstroms to 135 angstroms, or from 70 angstroms to 120 angstroms. 6.The method of claim 1, wherein the Column 6 metal catalyst has a surfacearea of at least 200 m²/g.
 7. The method of claim 1, wherein the Column6 metal catalyst comprises molybdenum, nickel, cobalt or mixturesthereof.
 8. The method of claim 1, wherein the Column 6 metal catalystfurther comprises one or more elements from Column 15 of the PeriodicTable and/or one or more compounds of one or more elements from Column15 of the Periodic Table.
 9. The method of claim 1, wherein thehydrocarbon feed has an API gravity of at most
 10. 10. The method ofclaim 1, wherein the crude product has an increase in API gravity of atleast 5 relative to the API gravity of the hydrocarbon feed.
 11. Themethod of claim 1, wherein the hydrocarbon feed has at least 0.01 gramsof C₅ asphaltenes per gram of hydrocarbon feed, and wherein the crudeproduct has a C₅ asphaltenes content of at most 90% of the hydrocarbonfeed C₅ asphaltenes content.
 12. The method of claim 1, wherein thehydrocarbon feed has a MCR content of at least 0.002 grams of MCR pergram of crude, and wherein the crude product has an MCR content of atmost 90% of the MCR content of the hydrocarbon feed MCR content.
 13. Themethod of claim 1, wherein the hydrocarbon feed has a viscosity of atleast 10 cSt at 37.8° C., and wherein the crude product has a viscosityat 37.8° C. of at most 50% of the viscosity of the hydrocarbon feed at37.8° C.
 14. The method of claim 1, wherein the crude product has aresidue content of at most 80%, at most 70%, or at most 60% of thehydrocarbon feed residue content.
 15. The method of claim 1, wherein thehydrocarbon feed is contacted with one or more catalysts in a fixed bedreactor.
 16. The method of claim 1, further comprising heating the oneor more catalysts to a temperature of at least 400° C. in a time periodof less than three weeks.
 17. The method of claim 16, wherein the one ormore catalysts are heated prior to contacting the hydrocarbon feed withthe one or more catalysts.
 18. The method of claim 1, wherein the methodfurther comprises fractionating the crude product into one or moredistillate fractions, and producing transportation fuel from at leastone of the distillate fractions.